DAQ-2024-004760

1

DAQC-070-24
Site ID 13031 (B1)

MEMORANDUM

TO: FILE – PACIFICORP ENERGY – Lake Side Power Plant

THROUGH: Harold Burge, Major Source Compliance Section Manager

FROM: Jeremiah R. Marsigli, Environmental Scientist

DATE: January 24, 2024

SUBJECT: FULL COMPLIANCE EVALUTION, Major, Utah County,
FRS #UT0000004904900241

INSPECTION DATE: January 11, 2024

MAILING ADDRESS: 1825 North Pioneer Lane, Vineyard, Utah County

SOURCE LOCATION: 1825 North Pioneer Lane, Vineyard, Utah County

SOURCE CONTACT(S): Veronica Reyes, Environmental Manager, 801-796-1916

OPERATING STATUS: Block 1 – operating
Block 2 – operating
PROCESS DESCRIPTION:

PacifiCorp operates a 500 MW block and a 629 MW block at a power plant in Vineyard, Utah. Each
block consists of two combined cycle combustion turbines (CT) and one steam turbine.

The plant operates as follows: The turbine generators operate on pipeline quality natural gas delivered to
the site from existing pipelines. The exhaust from each CT is routed to a heat recovery steam generator
(HRSG) to generate steam for the steam turbine generator. There is one HRSG for each CT. The steam
from the two HRSG are combined and sent to the steam turbine generator. An additional 50 MW may be
produced during peak load by utilizing duct firing and steam injection power augmentation. This project
will interconnect with the PacifiCorp transmission grid.

Emissions from the CT exhaust are controlled prior to entry into the steam turbine as follows: Each CT
has a selective catalytic reduction system (ammonia injection) in the HRSG to control NOx emissions and
an oxidation catalyst for control of CO and VOC emissions. In addition, dry low NOx combustors are
used in the CT. PM is controlled by using pipeline quality natural gas. CEMs are installed to analyze NOx
and CO concentrations and percentage of oxygen in the exhaust.

The dew point heater treats incoming natural gas to keep entrained liquid from condensing. This heater
operates on natural gas. An auxiliary boiler is used to provide seal steam to the steam turbine and
maintain optimal temperatures during the HRSG downtimes. It also allows for a quick startup of the
CT/HRSG. Lastly, there is an emergency generator and diesel fired fire pump.

APPLICABLE REGULATIONS: Title V Operating Permit 4900241002, dated July 16, 2021

0 3
2

SOURCE INSPECTION
EVALUATION:
SECTION I: GENERAL PROVISIONS

I.A Federal Enforcement.

All terms and conditions in this permit, including those provisions designed to limit the
potential to emit, are enforceable by the EPA and citizens under the Clean Air Act of 1990
(CAA) except those terms and conditions that are specifically designated as "State
Requirements". (R307-415-6b)

Status: This is not an inspection item.

I.B Permitted Activity(ies).

Except as provided in R307-415-7b(1), the permittee may not operate except in compliance
with this permit. (See also Provision I.E, Application Shield)

Status: In compliance. The permittee appeared to be complying with the conditions of this permit at
the time of the inspection.

I.C Duty to Comply.

I.C.1 The permittee must comply with all conditions of the operating permit. Any permit
noncompliance constitutes a violation of the Air Conservation Act and is grounds for any of
the following: enforcement action; permit termination; revocation and reissuance;
modification; or denial of a permit renewal application. (R307-415-6a(6)(a))

I.C.2 It shall not be a defense for a permittee in an enforcement action that it would have been
necessary to halt or reduce the permitted activity in order to maintain compliance with the
conditions of this permit. (R307-415-6a(6)(b))

I.C.3 The permittee shall furnish to the Director, within a reasonable time, any information that
the Director may request in writing to determine whether cause exists for modifying,
revoking and reissuing, or terminating this permit or to determine compliance with this
permit. Upon request, the permittee shall also furnish to the Director copies of records
required to be kept by this permit or, for information claimed to be confidential, the
permittee may furnish such records directly to the EPA along with a claim of
confidentiality. (R307-415-6a(6)(e))

I.C.4 This permit may be modified, revoked, reopened, and reissued, or terminated for cause. The
filing of a request by the permittee for a permit modification, revocation and reissuance, or
termination, or of a notification of planned changes or anticipated noncompliance shall not
stay any permit condition, except as provided under R307-415-7f(1) for minor permit
modifications. (R307-415-6a(6)(c))

Status:

In compliance. The permittee appeared to be in compliance with all conditions of this permit
at the time of inspection. This permit is not being modified, revoked, reopened, or terminated
at this time.

3

I.D Permit Expiration and Renewal.

I.D.1 This permit is issued for a fixed term of five years and expires on the date shown under
"Enforceable Dates and Timelines" at the front of this permit. (R307-415-6a(2))

I.D.2 Application for renewal of this permit is due on or before the date shown under
"Enforceable Dates and Timelines" at the front of this permit. An application may be
submitted early for any reason. (R307-415-5a(1)(c))

I.D.3 An application for renewal submitted after the due date listed in I.D.2 above shall be
accepted for processing, but shall not be considered a timely application and shall not
relieve the permittee of any enforcement actions resulting from submitting a late
application. (R307-415-5a(5))

I.D.4 Permit expiration terminates the permittee's right to operate unless a timely and complete
renewal application is submitted consistent with R307-415-7b (see also Provision I.E,
Application Shield) and R307-415-5a(1)(c) (see also Provision I.D.2). (R307-415-7c(2))

Status: In compliance. This permit has not expired and the application for renewal deadline has not
lapsed.

I.E Application Shield.

If the permittee submits a timely and complete application for renewal, the permittee's
failure to have an operating permit will not be a violation of R307-415, until the Director
takes final action on the permit renewal application. In such case, the terms and conditions
of this permit shall remain in force until permit renewal or denial. This protection shall
cease to apply if, subsequent to the completeness determination required pursuant to R307-
415-7a(3), and as required by R307-415-5a(2), the applicant fails to submit by the deadline
specified in writing by the Director any additional information identified as being needed to
process the application. (R307-415-7b(2))

Status: The deadline to submit an application for renewal and be covered under the Application
Shield is January 16, 2026.

I.F Severability.

In the event of a challenge to any portion of this permit, or if any portion of this permit is
held invalid, the remaining permit conditions remain valid and in force. (R307-415-6a(5))

Status: This is not an inspection item.

I.G Permit Fee.

I.G.1 The permittee shall pay an annual emission fee to the Director consistent with R307-415-9.
(R307-415-6a(7))

I.G.2 The emission fee shall be due on October 1 of each calendar year or 45 days after the source
receives notice of the amount of the fee, whichever is later. (R307-415-9(4)(a))

Status: In compliance. Emission fees have been paid as invoiced.
4

I.H No Property Rights.

This permit does not convey any property rights of any sort, or any exclusive privilege.
(R307-415-6a(6)(d))

Status: This is not an inspection item.

I.I Revision Exception.

No permit revision shall be required, under any approved economic incentives, marketable
permits, emissions trading and other similar programs or processes for changes that are
provided for in this permit. (R307-415-6a(8))

Status: This is not an inspection item.

I.J Inspection and Entry.

I.J.1 Upon presentation of credentials and other documents as may be required by law, the
permittee shall allow the Director or an authorized representative to perform any of the
following:

I.J.1.a Enter upon the permittee's premises where the source is located or emissions related
activity is conducted, or where records are kept under the conditions of this permit.
(R307-415-6c(2)(a))

I.J.1.b Have access to and copy, at reasonable times, any records that must be kept under
the conditions of this permit. (R307-415-6c(2)(b))

I.J.1.c Inspect at reasonable times any facilities, equipment (including monitoring and air
pollution control equipment), practice, or operation regulated or required under this
permit. (R307-415-6c(2)(c))

I.J.1.d Sample or monitor at reasonable times substances or parameters for the purpose of
assuring compliance with this permit or applicable requirements.
(R307-415-6c(2)(d))

I.J.2 Any claims of confidentiality made on the information obtained during an inspection shall
be made pursuant to Utah Code Ann. Section 19-1-306. (R307-415-6c(2)(e))

Status: In compliance. Access was granted to the facility and records. No claims of confidentiality
were made.

5

I.K Certification.

Any application form, report, or compliance certification submitted pursuant to this permit
shall contain certification as to its truth, accuracy, and completeness, by a responsible
official as defined in R307-415-3. This certification shall state that, based on information
and belief formed after reasonable inquiry, the statements and information in the document
are true, accurate, and complete. (R307-415-5d)

Status: In compliance. All documents submitted by the company have been signed by the responsible
official.

I.L Compliance Certification.

I.L.1 Permittee shall submit to the Director an annual compliance certification, certifying
compliance with the terms and conditions contained in this permit, including emission
limitations, standards, or work practices. This certification shall be submitted no later than
the date shown under "Enforceable Dates and Timelines" at the front of this permit, and that
date each year following until this permit expires. The certification shall include all the
following (permittee may cross-reference this permit or previous reports): (R307-415-6c(5))

I.L.1.a The identification of each term or condition of this permit that is the basis of the
certification;

I.L.1.b The identification of the methods or other means used by the permittee for
determining the compliance status with each term and condition during the
certification period. Such methods and other means shall include, at a minimum, the
monitoring and related recordkeeping and reporting requirements in this permit. If
necessary, the permittee also shall identify any other material information that must
be included in the certification to comply with section 113(c)(2) of the Act, which
prohibits knowingly making a false certification or omitting material information;

I.L.1.c The status of compliance with the terms and conditions of the permit for the period
covered by the certification, including whether compliance during the period was
continuous or intermittent. The certification shall be based on the method or means
designated in Provision I.L.1.b. The certification shall identify each deviation and
take it into account in the compliance certification. The certification shall also
identify as possible exceptions to compliance any periods during which compliance
is required and in which an excursion or exceedance as defined under 40 CFR Part
64 occurred; and

I.L.1.d Such other facts as the Director may require to determine the compliance status.

I.L.2 The permittee shall also submit all compliance certifications to the EPA, Region VIII, at the
following address or to such other address as may be required by the Director:
(R307-415-6c(5)(d))

6

Environmental Protection Agency, Region VIII
Office of Enforcement, Compliance and Environmental Justice
(mail code 8ENF)
1595 Wynkoop Street
Denver, CO 80202-1129

Status:

In compliance. The most recent annual compliance certification was received by DAQ on
March 14, 2023. This report was evaluated under separate cover and found in compliance
with the requirements of this condition.

I.M Permit Shield.

I.M.1 Compliance with the provisions of this permit shall be deemed compliance with any
applicable requirements as of the date of this permit, provided that:

I.M.1.a Such applicable requirements are included and are specifically identified in this
permit, or (R307-415-6f(1)(a))

I.M.1.b Those requirements not applicable to the source are specifically identified and listed
in this permit. (R307-415-6f(1)(b))

I.M.2 Nothing in this permit shall alter or affect any of the following:

I.M.2.a The emergency provisions of Utah Code Ann. Section 19-1-202 and Section 19-2-
112, and the provisions of the CAA Section 303. (R307-415-6f(3)(a))

I.M.2.b The liability of the owner or operator of the source for any violation of applicable
requirements under Utah Code Ann. Section 19-2-107(2)(g) and Section 19-2-110
prior to or at the time of issuance of this permit. (R307-415-6f(3)(b)

I.M.2.c The applicable requirements of the Acid Rain Program, consistent with the CAA
Section 408(a). (R307-415-6f(3)(c))

I.M.2.d The ability of the Director to obtain information from the source under Utah Code
Ann. Section 19-2-120, and the ability of the EPA to obtain information from the
source under the CAA Section 114. (R307-415-6f(3)(d))

Status: It appears that all applicable requirements have been included in this permit. Nothing in this
permit affects any of the items in I.M.2 above.

I.N Emergency Provision.

I.N.1 An "emergency" is any situation arising from sudden and reasonably unforeseeable events
beyond the control of the source, including acts of God, which situation requires immediate
corrective action to restore normal operation, and that causes the source to exceed a
technology-based emission limitation under this permit, due to unavoidable increases in
emissions attributable to the emergency. An emergency shall not include noncompliance to
the extent caused by improperly designed equipment, lack of preventive maintenance,
careless or improper operation, or operator error. (R307-415-6g(1))

7

I.N.2 An emergency constitutes an affirmative defense to an action brought for noncompliance
with such technology-based emission limitations if the affirmative defense is demonstrated
through properly signed, contemporaneous operating logs, or other relevant evidence that:

I.N.2.a An emergency occurred and the permittee can identify the causes of the emergency.
(R307-415-6g(3)(a))

I.N.2.b The permitted facility was at the time being properly operated. (R307-415-6g(3)(b))

I.N.2.c During the period of the emergency the permittee took all reasonable steps to
minimize levels of emissions that exceeded the emission standards, or other
requirements in this permit. (R307-415-6g(3)(c))

I.N.2.d The permittee submitted notice of the emergency to the Director within two
working days of the time when emission limitations were exceeded due to the
emergency. This notice must contain a description of the emergency, any steps
taken to mitigate emissions, and corrective actions taken. This notice fulfills the
requirement of Provision I.S.2.c below. (R307-415-6g(3)(d))

I.N.3 In any enforcement proceeding, the permittee seeking to establish the occurrence of an
emergency has the burden of proof. (R307-415-6g(4))

I.N.4 This emergency provision is in addition to any emergency or upset provision contained in
any other section of this permit. (R307-415-6g(5))

Status: There were no emergency events reported or recorded during the 12-month period preceding
this inspection.

I.O Operational Flexibility.

Operational flexibility is governed by R307-415-7d(1).

Status: This is not an inspection item.

I.P Off-permit Changes.

Off-permit changes are governed by R307-415-7d(2).

Status: This is not an inspection item.

I.Q Administrative Permit Amendments.

Administrative permit amendments are governed by R307-415-7e.

Status: This is not an inspection item.

I.R Permit Modifications.

Permit modifications are governed by R307-415-7f.

Status: This is not an inspection item.
8

I.S Records and Reporting.

I.S.1 Records.

I.S.1.a The records of all required monitoring data and support information shall be
retained by the permittee for a period of at least five years from the date of the
monitoring sample, measurement, report, or application. Support information
includes all calibration and maintenance records, all original strip-charts or
appropriate recordings for continuous monitoring instrumentation, and copies of all
reports required by this permit. (R307-415-6a(3)(b)(ii))

I.S.1.b For all monitoring requirements described in Section II, Special Provisions, the
source shall record the following information, where applicable:
(R307-415-6a(3)(b)(i))

I.S.1.b.1 The date, place as defined in this permit, and time of sampling or
measurement.

I.S.1.b.2 The date analyses were performed.

I.S.1.b.3 The company or entity that performed the analyses.

I.S.1.b.4 The analytical techniques or methods used.

I.S.1.b.5 The results of such analyses.

I.S.1.b.6 The operating conditions as existing at the time of sampling or
measurement.

I.S.1.c Additional record keeping requirements, if any, are described in Section II, Special
Provisions.

I.S.2 Reports.

I.S.2.a Monitoring reports shall be submitted to the Director every six months, or more
frequently if specified in Section II. All instances of deviation from permit
requirements shall be clearly identified in the reports. (R307-415-6a(3)(c)(i))

I.S.2.b All reports submitted pursuant to Provision I.S.2.a shall be certified by a
responsible official in accordance with Provision I.K of this permit. (R307-415-
6a(3)(c)(i)

I.S.2.c The Director shall be notified promptly of any deviations from permit requirements
including those attributable to upset conditions as defined in this permit, the
probable cause of such deviations, and any corrective actions or preventative
measures taken. Prompt, as used in this condition, shall be defined as written
notification within the number of days shown under "Enforceable Dates and
Timelines" at the front of this permit. Deviations from permit requirements due to
breakdowns shall be reported in accordance with the provisions of R307-107.
(R307-415-6a(3)(c)(ii))

9

I.S.3 Notification Addresses.

I.S.3.a All reports, notifications, or other submissions required by this permit to be
submitted to the Director are to be sent to the following address or to such other
address as may be required by the Director:

Utah Division of Air Quality
P.O. Box 144820
Salt Lake City, UT 84114-4820
Phone: [phone]

I.S.3.b All reports, notifications or other submissions required by this permit to be
submitted to the EPA should be sent to one of the following addresses or to such
other address as may be required by the Director:

For annual compliance certifications:

Environmental Protection Agency, Region VIII
Office of Enforcement, Compliance and Environmental Justice
(mail code 8ENF)
1595 Wynkoop Street
Denver, CO 80202-1129

For reports, notifications, or other correspondence related to permit modifications,
applications, etc.:

Environmental Protection Agency, Region VIII
Office of Partnerships and Regulatory Assistance Air and Radiation Program (mail
code 8P-AR)
1595 Wynkoop Street
Denver, CO 80202-1129
Phone: [phone]

Status: In compliance. Records were provided upon request during this inspection. Semi-annual
monitoring reports have been submitted.

I.T Reopening for Cause.

I.T.1 A permit shall be reopened and revised under any of the following circumstances:

I.T.1.a New applicable requirements become applicable to the permittee and there is a
remaining permit term of three or more years. No such reopening is required if the
effective date of the requirement is later than the date on which this permit is due to
expire, unless the terms and conditions of this permit have been extended pursuant
to R307-415-7c(3), application shield. (R307-415-7g(1)(a))

I.T.1.b The Director or EPA determines that this permit contains a material mistake or that
inaccurate statements were made in establishing the emissions standards or other
terms or conditions of this permit. (R307-415-7g(1)(c))

10

I.T.1.c EPA or the Director determines that this permit must be revised or revoked to
assure compliance with applicable requirements. (R307-415-7g(1)(d))

I.T.1.d Additional applicable requirements are to become effective before the renewal date
of this permit and are in conflict with existing permit conditions. (R307-415-
7g(1)(e))

I.T.2 Additional requirements, including excess emissions requirements, become applicable to a
Title IV affected source under the Acid Rain Program. Upon approval by EPA, excess
emissions offset plans shall be deemed to be incorporated into this permit.
(R307-415-7g(1)(b))

I.T.3 Proceedings to reopen and issue a permit shall follow the same procedures as apply to initial
permit issuance and shall affect only those parts of this permit for which cause to reopen
exists. (R307-415-7g(2))

Status: This is not an inspection item. Reopening is handled by DAQ’s engineering section.

I.U Inventory Requirements.

An emission inventory shall be submitted in accordance with the procedures of R307-150,
Emission Inventories. (R307-150)

Status: In compliance. Emission inventories have been submitted as required.

I.V Title IV and Other, More Stringent Requirements

Where an applicable requirement is more stringent than an applicable requirement of
regulations promulgated under Title IV of the Act, Acid Deposition Control, both
provisions shall be incorporated into this permit. (R307-415-6a(1)(b))

Status: This is not an inspection item.
SECTION II: SPECIAL PROVISIONS

II.A Emission Unit(s) Permitted to Discharge Air Contaminants.
(R307-415-4(3)(a) and R307-415-4(4))

II.A.1 Permitted Source
Source-wide (Typical full-load heat input under expected average conditions are listed for each emission
unit)

II.A.2 #11 Combustion Gas Turbine (EU#1)
Natural gas-fired (1801 MMBtu/hr), lean premix dry low-NOx combustion turbine (NSPS GG) with a
HRSG, a low NOx duct burner (184 MMBtu/hr, NSPS Db), with emissions control by a selective catalytic
reduction (SCR) system with ammonia injection and a CO catalyst, commenced construction on March
27, 2004

11

II.A.3 #12 Combustion Gas Turbine (EU#2)
Natural gas-fired (1801 MMBtu/hr), lean premix dry low-NOx combustion turbine (NSPS GG) with a
HRSG, a low NOx duct burner (184 MMBtu/hr, NSPS Db), with emissions control by a selective catalytic
reduction (SCR) system with ammonia injection and a CO catalyst, commenced construction on March
27, 2004

II.A.4 Block #1 Combustion Gas Turbines (EU#3)
Includes EU#1 and EU#2

II.A.5 Auxiliary Boiler #1 (EU#4)
Natural gas-fired 62.765 MMBtu/hr auxiliary boiler for Block #1, NSPS Dc and NESHAP DDDDD

II.A.6 Fuel Dew Point Heater (EU#5)
One 4.76 MMBtu/hr fuel dew point heater. No unit-specific applicable requirements

II.A.7 Emergency Diesel Generator #1 (EU#6)
One 1500 hp diesel-fired emergency generator for Block #1, manufactured in January 2005. This unit
meets the definition of emergency stationary RICE in 40 CFR 63.6675(b)(1) and is not operated or
contractually obligated to be available for more than 15 hours per calendar year for the purposes specified
in 40 CFR 63.6640(f(2)(ii) and (iii). This unit is subject to limited requirements from 40 CFR 63 Subpart
ZZZZ

II.A.8 Emergency Diesel Fire Pump (EU#7)
One 290 hp diesel-fired fire pump, manufactured in December 2006, NSPS IIII

II.A.9 Cooling Tower #1 (EU#8)
One 10 cell mechanical draft evaporative cooling tower with drift elimination. No unit-specific applicable
requirements

II.A.10 #21 Combustion Gas Turbine (EU#9)
Natural gas-fired (1762 MMBtu/hr) lean premix dry low-NOx combustion turbine with a HRSG, a low
NOx duct burner (400 MMBtu/hr), with emissions control by a selective catalytic reduction (SCR) system
with ammonia injection and a CO catalyst, commenced construction on May 13, 2014, NSPS KKKK

II.A.11 #22 Combustion Gas Turbine (EU#10)
Natural gas-fired (1762 MMBtu/hr) lean premix dry low-NOx combustion turbine with a HRSG, a low
NOx duct burner (400 MMBtu/hr), with emissions control by a selective catalytic reduction (SCR) system
with ammonia injection and a CO catalyst, commenced construction on May 13, 2011, NSPS KKKK

II.A.12 Block #2 Combustion Gas Turbines (EU#11)
Includes EU#9 and EU#10

II.A.13 Cooling Tower #2 (EU #12)
One 16 cell mechanical draft evaporative cooling tower with drift elimination. No unit-specific applicable
requirements

II.A.14 Auxiliary Boiler #2 (EU#13)
Natural gas-fired 61.2 MMBtu/hr auxiliary boiler for Block #2, NSPS Dc and NESHAP DDDDD

II.A.15 Emergency Diesel Generator #2 (EU#14)
One 1500 hp diesel-fired emergency generator for Block #2, post 2007 model, NSPS IIII
12

II.A.16 Misc. Activities (EU# 15)
Include abrasive blasting, welding, storage tanks, solvent cleaning (< 30 gallons/year), etc.

Status: In compliance. No unapproved equipment was observed onsite.

II.B Requirements and Limitations

The following emission limitations, standards, and operational limitations apply to the permitted facility
as indicated:

II.B.1 Conditions on permitted source (Source-wide)

II.B.1.a Condition:

At all times, including periods of startup, shutdown, and malfunction, the permittee shall, to the extent
practicable, maintain and operate any permitted plant equipment, including associated air pollution
control equipment, in a manner consistent with good air pollution control practice for minimizing
emissions. Determination of whether acceptable operating and maintenance procedures are being used
will be based on information available to the Director which may include, but is not limited to,
monitoring results, opacity observations, review of operating and maintenance procedures, and inspection
of the source. [Origins: DAQE -AN130310012-15]. [40 CFR 60 Subpart A, R307-401-8(2)]

II.B.1.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.a.2 Recordkeeping:

Permittee shall document activities performed to assure proper operation and maintenance.
Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.1.a.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. The facility appeared to be well maintained. PacifiCorp utilizes a SAP software
program to track and record their preventative maintenance program.

II.B.1.b Condition:

Visible emissions shall be no greater than 20 percent opacity for all emission units unless otherwise
specified in this permit. [Origins: DAQE -AN130310012-15]. [R307-401-8]

II.B.1.b.1 Monitoring:

A visual opacity survey of each affected emission unit shall be performed on a monthly basis by
an individual trained on the observation procedures of 40 CFR 60, Appendix A, Method 9. If
visible emissions other than steam are observed from an emission unit, an opacity determination
of that emission unit shall be performed by a certified observer within 24 hours of the initial
survey. The opacity determination shall be performed in accordance with 40 CFR 60, Appendix
13

A, Method 9. If opacity exceeds the limit, maintenance shall be performed on the affected unit to
correct the problem.

II.B.1.b.2 Recordkeeping:

A log of the visual opacity survey(s) shall be maintained in accordance with Provision I.S.1 of
this permit. If an opacity determination is indicated, a notation of the determination shall be made
in the log. All data required by 40 CFR 60, Appendix A, Method 9 shall also be maintained in
accordance with Provision I.S.1 of this permit. If excess visible emission is indicated, a notation
of the resulting maintenance activity shall also be made in the log, and shall include the date of
the maintenance request, the date the maintenance was performed, the type of maintenance
performed, and the name of the person responsible for the maintenance.

II.B.1.b.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Visible opacity surveys had been performed and recorded as required. No opacity
was observed during this inspection.

II.B.1.c Condition:

Emergency generators shall be used for electricity producing operation only during the periods when
electric power from the public utilities is interrupted, and for regular maintenance and testing. [Origin:
DAQE-AN130310012-15]. [R307-401-8]

II.B.1.c.1 Monitoring:

All operation logs shall be used to record the following information for each usage: dates(s), total
hours used, and reason for usage.

II.B.1.c.2 Recordkeeping:

Results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.1.c.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Emergency generators and fire pumps were not used for energy production during
the 12-month period preceding this inspection. Emergency generator and fire pump use logs were
kept and included all the required information. Generators have been exercised for 30 minutes
weekly.

II.B.1.d Condition:

Sulfur content of the fuel oil combusted shall be no greater than 0.0015 % by weight unless otherwise
specified in this permit. [Origins: DAQE -AN130310012-15]. [R307-203-1, R307-401-8]

14

II.B.1.d.1 Monitoring:

For each delivery of oil, the permittee shall either:

(a) Determine the fuel sulfur content expressed as wt% in accordance with the methods of the
American Society for Testing Materials (ASTM); or

(b) Inspect the fuel sulfur content expressed as wt% determined by the vendor using methods of
the ASTM.

II.B.1.d.2 Recordkeeping:

Results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.1.d.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. Fuel oil deliveries have not contained sulfur content greater than 15 ppm. The latest
delivery was received from Christensen Oil, and a fuel trip ticket indicating sulfur content was kept
on file.

II.B.1.e Condition:

The permittee shall use # 1 or #2 fuel oil or diesel fuel in the emergency fire pump and generators.
[DAQE-AN130310012-15]. [R307-401-8]

II.B.1.e.1 Monitoring:

In lieu of fuel monitoring, the report required for this permit condition will serve as monitoring.

II.B.1.e.2 Recordkeeping:

The annual certification required for this permit condition shall be maintained as described in
Provision I.S.1 of the permit.

II.B.1.e.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify with each annual certification report that fuel usage in each affected unit is in compliance
with the permit condition during the reporting year.

Status: In compliance. The permittee has certified compliance with this condition in the annual compliance
certification.

15

II.B.1.f Condition:

The permittee shall comply with the applicable requirements for recycling and emission reduction for
Class I and Class II refrigerants and their substitutes pursuant to 40 CFR 82, Subpart F - Recycling and
Emissions Reduction. [40 CFR 82.150(b)]. [40 CFR 82]

II.B.1.f.1 Monitoring:

The permittee shall certify, in the annual compliance statement required in Section I of this
permit, its compliance status with the requirements of 40 CFR 82, Subpart F.

II.B.1.f.2 Recordkeeping:

All records required in 40 CFR 82, Subpart F shall be maintained consistent with the
requirements of Provision S.1 in Section I of this permit.

II.B.1.f.3 Reporting:

All reports required in 40 CFR 82, Subpart F shall be submitted as required. There are no
additional reporting requirements except as outlined in Section I of this permit.

Status: In compliance. The permittee has certified compliance with this condition in the annual compliance
certification.

II.B.2 Conditions on Block #1 Combustion Gas Turbines (EU#3)

II.B.2.a Condition:

Emissions of NOx from each HRSG stack shall be no greater than 2.0 ppmvd @ 15% O2 and 14.9 lb/hr
based on a 3-hour block average under steady state operation and shall not exceed 25 ppmv, dry @ 15%
O2 during short-term excursions. Steady state operation and short-term excursions are defined in
Condition II.B.2.f and II.B.2.e of this permit, respectively. [Origins: DAQE -AN130310012-15 & SIP
IX.H.3.c.i.A and IX.H.3.c.iii.IV]. [R307-110-7, R307-401-8, R307-403-3(3)(a)(LAER)]

II.B.2.a.1 Monitoring:

The permittee shall install, certify, maintain, operate, and quality-assure a continuous emissions
monitoring system (CEMS) to determine compliance with the applicable NOx limitations as
specified below:

(a) Each NOx and diluent CEMS must be installed and certified according to Performance
Specification 2 (PS 2) and PS 3 (for diluent) in Appendix B of 40 CFR 60, except the 7-day
calibration drift is based on unit operating days, not calendar days. Procedure 1 in Appendix F of
40 CFR 60 is not required. Alternatively, a NOx diluent CEMS that is installed and certified
according to Appendix A of 40 CFR 75 shall be acceptable for use. The relative accuracy test
audit (RATA) of the CEMS shall be performed in accordance with 40 CFR 60.334(b)(1).

(b) As specified in 40 CFR 60.13(e)(2), during each full unit operating hour, each monitor must
complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each
15-minute quadrant of the hour, to validate the hour. For partial unit operating hours, at least one
valid data point must be obtained for each quadrant of the hour in which the unit operates. For
16

unit operating hours in which required quality assurance and maintenance activities are
performed on the CEMS, a minimum of two valid data points (one in each of two quadrants) are
required to validate the hour. (c) For purposes of identifying excess emissions, CEMS data must
be reduced to hourly averages as specified in 40 CFR 60.13(h).

(i) For each unit operating hour in which a valid hourly average, as described in paragraph (b) of
this section, is obtained for both NOx and diluent, the data acquisition and handling system must
calculate and record the hourly NOx emissions in the units of the applicable NOx emission
standard under this permit, i.e., percent NOx by volume, dry basis, corrected to 15 percent O2 and
International Organization for Standardization (ISO) standard conditions. For any hour in which
the hourly average O2 concentration exceeds 19.0 percent O2, a diluent cap value of 19.0 percent
O2 may be used in the emission calculations.

(ii) A worst case ISO correction factor may be calculated and applied using historical ambient
data. For the purpose of this calculation, substitute the maximum humidity of ambient air (Ho),
minimum ambient temperature (Ta), and minimum combustor inlet absolute pressure (Po) into
the ISO correction equation.

(iii) If the permittee has installed a NOx CEMS to meet the requirements of 40 CFR 75, and is
continuing to meet the ongoing requirements of 40 CFR 75, the CEMS may be used to meet the
requirements of this section, except that the missing data substitution methodology provided for
at 40 CFR 75, Subpart D, is not required for purposes of identifying excess emissions. Instead,
periods of missing CEMS data are to be reported as monitor downtime in the excess emissions
and monitoring performance report required in 40 CFR 60.7(c).

(d) During short-term excursions, NOx emissions shall be calculated and averaged from the data
collected from CEMS during this period of time. [40 CFR 60 Subpart GG]

II.B.2.a.2 Recordkeeping:

Results of NOx monitoring shall be recorded and maintained as required in R307-170, 40 CFR 60
Subpart GG, 40 CFR 75 Subpart F, and as described in Provision I.S.1 of this permit.

II.B.2.a.3 Reporting:

(a) The permittee shall comply with the reporting provisions in R307-170-9, 40 CFR 75 Subpart
G, 40 CFR 60 Subpart GG and all the reporting provisions contained in Section I of this permit.

(b) The permittee shall submit reports of excess emissions and monitor downtime, in accordance
with 40 CFR 60.7(c). Excess emissions shall be reported for all periods of unit operation,
including startup, shutdown and malfunction. For the purpose of reports required under 40 CFR
60.7(c), periods of excess emissions and monitor downtime that shall be reported are defined as
follows:

(1) Excess emissions shall be any unit operating period in which the 3-hour block average NOx
concentration exceeds the applicable emission standard in this condition. A "3-hour block
average NOx emission rate'' is the arithmetic average of the valid hourly NOx emission rate in
units of the applicable NOx emission standard of this permit condition measured by the CEMS
during fixed 3-hour blocks beginning at midnight. The permittee shall calculate the block average
if a valid NOx emission rate is obtained for at least 2 of the 3 hours.
(2) An hour of excess emission during short-term excursions shall be any unit operating period in
17

which average NOx concentration exceeds applicable emission standards in this permit condition.
For partial unit operating hours during short-term excursions, at least one valid data point must be
obtained with each monitor for each quadrant of hour in which the unit operates. The data
obtained during the partial unit operating hours shall be used to calculate the average emissions.

(3) A period of monitor downtime shall be any unit operating hour in which the data for any of
the following parameters are either missing or invalid: NOx concentration, CO2 or O2
concentration, fuel flow rate, or megawatts.
(4) For operating periods during which multiple emissions standards apply, the applicable
standard is the average of the applicable standards during each hour. For hours with multiple
emissions standards, the applicable limit for that hour is determined based on the condition that
corresponded to the more stringent standard.

(c) All reports of excess emissions and monitor downtime shall be postmarked by the 30th day
following the end of each calendar quarter.

(d) The quarterly reports required in R307-170-9 and 40 CFR 75 Subpart G are considered
prompt notification of permit deviations required in Provision I.S.2.c of this permit if all
information required by Provision I.S.2.c is included in the report.

Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.2.b Condition:

Emissions of NOx shall be no greater than 112.0 ppmvd @ 15% O2 from each turbine based on a 4-hour
rolling average during unit operations. [40 CFR 60.332(a)(1)]. [40 CFR 60 Subpart GG]

II.B.2.b.1 Monitoring:

The permittee shall install, certify, maintain, operate, and quality-assure a continuous emissions
monitoring systems (CEMS) to determine compliance with the applicable NOx limitations as
specified below:

(a) Each NOx and diluent CEMS must be installed and certified according to Performance
Specification 2 (PS 2) and PS 3 (for diluent) in Appendix B of 40 CFR 60, except the 7-day
calibration drift is based on unit operating days, not calendar days. Procedure 1 in Appendix F of
40 CFR 60 is not required. Alternatively, a NOx diluent CEMS that is installed and certified
according to Appendix A of 40 CFR 75 shall be acceptable for use. The relative accuracy test
audit (RATA) of the CEMS shall be performed in accordance with 40 CFR 60.334(b)(1).

(b) As specified in 40 CFR 60.13(e)(2), during each full unit operating hour, each monitor must
complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each
15-minute quadrant of the hour, to validate the hour. For partial unit operating hours, at least one
valid data point must be obtained for each quadrant of the hour in which the unit operates. For
unit operating hours in which required quality assurance and maintenance activities are
performed on the CEMS, a minimum of two valid data points (one in each of two quadrants) are
required to validate the hour.

(c) For purposes of identifying excess emissions, CEMS data must be reduced to hourly averages
as specified in 40 CFR 60.13(h).

18

(i) For each unit operating hour in which a valid hourly average, as described in paragraph (b) of
this section, is obtained for both NOx and diluent, the data acquisition and handling system must
calculate and record the hourly NOx emissions in the units of the applicable NOx emission
standard under this permit, i.e., percent NOx by volume, dry basis, corrected to 15 percent O2 and
International Organization for Standardization (ISO) standard conditions. For any hour in which
the hourly average O2 concentration exceeds 19.0 percent O2, a diluent cap value of 19.0 percent
O2 may be used in the emission calculations.

(ii) A worst case ISO correction factor may be calculated and applied using historical ambient
data. For the purpose of this calculation, substitute the maximum humidity of ambient air (Ho),
minimum ambient temperature (Ta), and minimum combustor inlet absolute pressure (Po) into
the ISO correction equation.

(iii) If the permittee has installed a NOx CEMS to meet the requirements of 40 CFR 75, and is
continuing to meet the ongoing requirements of 40 CFR 75, the CEMS may be used to meet the
requirements of this section, except that the missing data substitution methodology provided for
at 40 CFR 75, Subpart D, is not required for purposes of identifying excess emissions. Instead,
periods of missing CEMS data are to be reported as monitor downtime in the excess emissions
and monitoring performance report required in 40 CFR 60.7(c). [40 CFR 60 Subpart GG]

II.B.2.b.2 Recordkeeping:

Results of NOx monitoring shall be recorded and maintained as required in 40 CFR 60 Subpart
GG, 40 CFR 75 Subpart F, and as described in Provision I.S.1 of this permit. [40 CFR 60 Subpart
GG]

II.B.2.b.3 Reporting:

(a) The permittee shall comply with the reporting provisions in 40 CFR 75 Subpart G and 40 CFR
Subpart GG and all the reporting provisions contained in Section I of this permit.

(b) The permittee shall submit reports of excess emissions and monitor downtime, in accordance
with 40 CFR 60.7(c). Excess emissions shall be reported for all periods of unit operation,
including startup, shutdown and malfunction. For the purpose of reports required under 40 CFR
60.7(c), periods of excess emissions and monitor downtime that shall be reported are defined as
follows:

(1) An hour of excess emissions shall be any unit operating period in which the 4-hour rolling
average NOx concentration exceeds applicable NSPS emission standard of 112.0 ppm (15% O2).
A "4-hour rolling average NOx emission rate'' is the arithmetic average of the average NOx
emission rate in ppm measured by the CEMS for a given hour and the three-unit operating hour
average NOx emission rates immediately preceding that unit operating hour. The permittee shall
calculate the rolling average if a valid NOx emission rate is obtained for at least 3 of the 4 hours.

(2) A period of monitor downtime shall be any unit operating hour in which the data for any of
the following parameters are either missing or invalid: NOx concentration, CO2 or O2
concentration, fuel flow rate, or megawatts.

(3) For operating periods during which multiple emissions standards apply, the applicable
standard is the average of the applicable standards during each hour. For hours with multiple
emissions standards, the applicable limit for that hour is determined based on the condition that
19

corresponded to the more stringent standard.

(4) All reports of excess emissions and monitor downtime shall be postmarked by the 30th day
following the end of each calendar quarter.

(c) The quarterly reports required in R307-170-9 and 40 CFR 75 Subpart G are considered
prompt notification of permit deviations required in Provision I.S.2.c of this permit if all
information required by Provision I.S.2.c is included in the report. [40 CFR 60 Subpart GG]

Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.2.c Condition:

Emissions of NOx shall be no greater than 0.20 lb/MMBTU from each duct burner based on a 30-day
rolling average as determined by the arithmetic average of all valid hourly emissions for the 30 successive
boiler operating days. [40 CFR 60.44b(a) and 40 CFR 60.44(b)(i)]. [40 CFR 60 Subpart Db]

II.B.2.c.1 Monitoring:

The permittee shall install, certify, maintain, operate, and quality-assure a continuous emissions
monitoring systems (CEMS) to determine compliance with the applicable NOx limitations as
specified below:

(a) Each NOx and diluent CEMS must be installed and certified according to Performance
Specification 2 (PS 2) and PS 3 (for diluent) in Appendix B of 40 CFR 60, except the 7-day
calibration drift is based on unit operating days, not calendar days. Procedure 1 in Appendix F of
40 CFR 60 is not required. Alternatively, a NOx diluent CEMS that is installed and certified
according to Appendix A of 40 CFR 75 shall be acceptable for use. The relative accuracy test
audit (RATA) of the CEMS shall be performed in accordance with 40 CFR 60.334(b)(1).

(b) As specified in 40 CFR 60.13(e)(2), during each full unit operating hour, each monitor must
complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each
15-minute quadrant of the hour, to validate the hour. For partial unit operating hours, at least one
valid data point must be obtained for each quadrant of the hour in which the unit operates. For
unit operating hours in which required quality assurance and maintenance activities are
performed on the CEMS, a minimum of two valid data points (one in each of two quadrants) are
required to validate the hour.

(c) For purposes of identifying excess emissions, CEMS data must be reduced to hourly averages
as specified in 40 CFR 60.13(h).

(i) For each unit operating hour in which a valid hourly average, as described in paragraph (b) of
this section, is obtained for both NOx and diluent, the data acquisition and handling system must
calculate and record the hourly NOx emissions in the units of the applicable NOx emission
standard under this permit, i.e., percent NOx by volume, dry basis, corrected to 15 percent O2 and
International Organization for Standardization (ISO) standard conditions. For any hour in which
the hourly average O2 concentration exceeds 19.0 percent O2, a diluent cap value of 19.0 percent
O2 may be used in the emission calculations.

20

(ii) A worst case ISO correction factor may be calculated and applied using historical ambient
data. For the purpose of this calculation, substitute the maximum humidity of ambient air (Ho),
minimum ambient temperature (Ta), and minimum combustor inlet absolute pressure (Po) into
the ISO correction equation.

(iii) If the permittee has installed a NOx CEMS to meet the requirements of 40 CFR 75, and is
continuing to meet the ongoing requirements of 40 CFR 75, the CEMS may be used to meet the
requirements of this section, except that the missing data substitution methodology provided for
at 40 CFR 75, Subpart D, is not required for purposes of identifying excess emissions. Instead,
periods of missing CEMS data are to be reported as monitor downtime in the excess emissions
and monitoring performance report required in 40 CFR 60.7(c). [40 CFR 60 Subpart Db]

II.B.2.c.2 Recordkeeping:

Results of NOx monitoring shall be recorded and maintained as required in 40 CFR 60 Subpart
Db, 40 CFR 75 Subpart F, and as described in Provision I.S.1 of this permit.
[40 CFR 60 Subpart Db]

II.B.2.c.3 Reporting:

(a) The permittee shall comply with the reporting provisions in 40 CFR 75 Subpart G, 40 CFR 60
Subpart Db, and all the reporting provisions contained in Section I of this permit.

(b) The permittee shall submit reports of excess emissions and monitor downtime, in accordance
with 40 CFR 60.7(c). Excess emissions shall be reported for all periods of unit operation,
including startup, shutdown and malfunction. For the purpose of reports required under 40 CFR
60.7(c), periods of excess emissions and monitor downtime that shall be reported are defined as
follows:

(1) An excess emission shall be any unit operating period in which the 30-day rolling average
NOx concentration exceeds the applicable limit. A "30-day rolling average NOx emission rate'' is
the arithmetic average of all hourly NOx emission data in lb/MMBtu measured by the CEMS for
a given day and the twenty-nine unit operating days average NOx emission rates immediately
preceding that unit operating day. A new 30-day average is calculated each unit operating day as
the average of all hourly NOx emissions rates for the preceding 30-unit operating days if a valid
NOx emission rate is obtained for at least 75 percent of all operating hours.

(2) A period of monitor downtime shall be any unit operating hour in which the data for any of
the following parameters are either missing or invalid: NOx concentration, CO2 or O2
concentration, fuel flow rate, or megawatts.

(3) For operating periods during which multiple emissions standards apply, the applicable
standard is the average of the applicable standards during each hour. For hours with multiple
emissions standards, the applicable limit for that hour is determined based on the condition that
corresponded to the more stringent standard.

(4) All reports of excess emissions and monitor downtime shall be postmarked by the 30th day
following the end of each calendar quarter.

21

(c) The quarterly reports required in R307-170-9 and 40 CFR 75 Subpart G are considered
prompt notification of permit deviations required in Provision I.S.2.c of this permit if all
information required by Provision I.S.2.c is included in the report. [40 CFR 60 Subpart Db]

Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.2.d Condition:

Emissions of CO from each HRSG stack shall be no greater than 3.0 ppmvd @ 15% O2 and 14.1 lb/hr
based on a 3-hour block average under steady state operation and shall not exceed 50 ppmv, dry @ 15%
O2 during short-term excursions. Steady state operation and short-term excursions are defined in
Condition II.B.2.f and II.B.2.e of this permit, respectively. [Origins: DAQE -AN130310012-15].
[R307-401-8]

II.B.2.d.1 Monitoring:

The emission of CO shall be monitored by continuous emission monitoring systems (CEMS)
consisting of CO and O2 monitors. The O2 monitor shall be used to adjust the measured CO
concentrations to 15% O2. The permittee shall calibrate, maintain, and operate a CEMS as
required by R307-170 to determine compliance with CO concentration. The quality assurance
requirements of R307-170, Continuous Emission Monitoring Systems Program shall be used to
fulfill data quality assurance requirements.

(1) Under steady state operation, the hourly average of CO emissions shall be calculated every
hour and the 3-hour block average shall be calculated using the hourly average data.

(2) During short-term excursions, CO emissions shall be calculated and averaged using the data
collected from CEMS during this period of time.

II.B.2.d.2 Recordkeeping:

Results of CO monitoring shall be recorded and maintained as required in R307-170 and as
described in Provision I.S.1 of this permit.

II.B.2.d.3 Reporting:

The permittee shall comply with the reporting provisions in R307-170-9 and all the reporting
provisions contained in Section I of this permit. The quarterly reports required in R307-170-9 is
considered prompt notification of permit deviations required in Provision I.S.2.c of this permit if
all information required by Provision I.S.2.c is included in the report.

Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.2.e Condition:

Short-term excursions are defined as 15-minute periods designated by the permittee that are the direct
result of transient load conditions when the 15-minute average CO or NOx concentration exceeds 3.0
ppmv and 2.0 ppmv, dry @ 15% O2, respectively. Short-term excursions shall not exceed four
consecutive 15-minute periods and shall not exceed a cumulative total of 160 hours annually. Transient
load conditions include the following:

22

(1) Initiation/shutdown of combustion turbine inlet air cooling

(2) Rapid combustion turbine load changes

(3) Initiation/shutdown of HRSG duct burners

(4) Provision of Ancillary Services and Automatic Generation Control.

[DAQE-AN130310012-15 & SIP IX.H.3.iii.A.III and IX.H.3.iii.C.III]. [R307-110-17, R307-401-8]

II.B.2.e.1 Monitoring:

Total hours of short-term excursions shall be determined by January 30 of each year using the
records required in this permit condition.

II.B.2.e.2 Recordkeeping:

Records of each short-term excursion shall be maintained in accordance with Provision I.S.1 of
this permit. The records shall include

(a) Date and time that the short-term excursions occur

(b) Duration (total minutes or hours) of each short-term excursion

(c) 15-minute average CO and NOx concentrations of each short-term excursion

(d) Cause of each short-term excursion.

II.B.2.e.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Short term excursion were reviewed onsite during this inspection. No 15-minute
excursions were recorded for Block #1 during the 12-month period ending December 31, 2023.

II.B.2.f Condition:

Steady state operation means all periods of combustion turbine operation, except for periods of startup
and shutdown as defined below, and periods of transient load conditions as defined in II.B.2.e of this
permit. Startup is defined as the period beginning with turbine initial firing until the unit stabilizes at the
NOx and CO emission limits of 2.0 ppmvd and 3.0 ppmvd, @15% O2, respectively, for steady state
operation. Shutdown is defined as the period beginning with the initiation of turbine shutdown sequence
and ending with the cessation of firing of the gas turbine engine. Startup and shutdown events shall not
exceed 613.5 hours per turbine per rolling 12-month period and emissions during startup and shutdown
are counted toward the applicable annual emission limitations. The cumulative startup and shutdown
period shall not exceed 14-hours per turbine in any one calendar day, commencing at midnight and
ending at the following midnight. [DAQE-AN130310012-15 & SIP IX.H.iii.A.I and II]. [R307-110-7,
R307-401-8]

23

II.B.2.f.1 Monitoring:

Daily total duration shall be calculated when startup or shutdown occurs. Total hours of startup
and shutdown shall be determined by January 30 of each year using the records required in this
permit condition.

II.B.2.f.2 Recordkeeping:

Records of each startup and shutdown shall be maintained in accordance with Provision I.S.1 of
this permit. The records shall include

(a) Date and time that the startup or shutdown occurs,

(b) Duration (total minutes or hours) of each startup or shutdown event,

(c) Cause of each startup or shutdown.

II.B.2.f.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Records were provided and reviewed. The 14 hour daily cumulative startup and
shutdown limit was not exceeded during the 12-month period preceding this inspection. The 613.5
hours per turbine per 12-month period was not exceeded. 21.9 hours were recorded for Block #1
during calendar year 2023.

II.B.2.g Condition:

Emissions of PM10 shall be no greater than 10.8 lb/hr (0.01 lb/MMBTU) from each HRSG stack based on
a 30-day rolling average. [DAQE-AN130310012-15]. [R307-401-8, R307-403-3(3)(a)(LAER)]

II.B.2.g.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every year. Tests may also be required at the direction of
the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
location.

(d) Methods.

24

(1) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 " SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

(2) For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR
51, Appendix M, Methods 201, 201a and 202, or other testing methods approved by EPA and
acceptable to the Director. All particulate captured shall be considered PM10. The back half
condensables shall be used for compliance demonstration as well as for inventory purposes.

(3) For stacks in which liquid drops are present, methods to eliminate the liquid drops should be
explored. If no reasonable method to eliminate the drops exists, then the following methods shall
be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing
methods approved by EPA and acceptable to the Director. The back half condensables shall also
be tested using the method specified by the Director. The portion of the front half of the catch
considered PM10 shall be based on information in Appendix B of the fifth edition of the EPA
document, AP-42, or other data acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.2.g.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.2.g.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: Compliance status is pending. Stack testing was last conducted May 18-19, 2023. Test results were
submitted to DAQ and await a complete audit. According to contractor calculated results,
emissions of PM10 from CT11 were above the permit limit. A retest was performed July 14, 2023,
and also failed to meet the permitted emission limit. A third test was performed August 4, 2023, and
contractor calculated test results indicate compliance at 7.78 lb/hr. A DAQ audit of stack testing
results is underway. Compliance status and recommendations for enforcement action will be made
outside this memorandum.

CT12 was last tested for PM10 on May 19, 2023. Results were submitted to DAQ along with results
for CT11 and await DAQ audit. Contractor calculated results for PM10 were 9.8 lb/hr.

25

II.B.2.h Condition:

Sulfur content of any fuel combusted shall be no greater than 0.8 percent. [40 CFR 60.333(b)].
[40 CFR 60 Subpart GG]

II.B.2.h.1 Monitoring:

In lieu of monitoring the total sulfur content of gaseous fuel combusted in the turbines, the
permittee shall use one of the following sources of information to demonstrate that the gaseous
fuel meets the definition of natural gas in 40 CFR 60.331(u):

(a) The gas quality characteristics in a current, valid purchase contract, tariff sheet or
transportation contract for the gaseous fuel, specifying that the maximum total sulfur content of
the fuel is 20.0 grains/100 scf or less; or

(b) Representative fuel sampling data which show that the sulfur content of the gaseous fuel does
not exceed 20 grains/100 scf. At a minimum, the amount of fuel sampling data specified in
Section 2.3.1.4 or 2.3.2.4 of Appendix D to 40 CFR Part 75 is required. [40 CFR 60 Subpart GG]

II.B.2.h.2 Recordkeeping:

Fuel receipt records showing sulfur content of the delivered fuel, gross heating value, and
density; or records of all sulfur content testing performed on the delivered fuel shall be
maintained in accordance with Provision I.S.1. of this permit.

II.B.2.h.3 Reporting:

The results of the testing shall be submitted semi-annually to the Director and to EPA. Any
deviations from this provision shall be promptly reported to the Director and to EPA; and
included in the semi-annual monitoring report. All reports shall be in accordance with Provision
I.S.2 of this permit.

Status: In compliance. The source burns only pipeline quality natural gas. A tariff sheet is available for
review.

II.B.2.i Condition:

Visible emissions shall be not greater than 10% opacity from each gas turbine and duct burner [DAQE-
AN130310012-15]. [R307-401-8]

II.B.2.i.1 Monitoring:

The annual certification required for this permit condition will serve as monitoring.

II.B.2.i.2 Recordkeeping:

The annual certification required for this permit condition shall be maintained as described in
Provision I.S.1 of the permit.

26

II.B.2.i.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. The source certified compliance with this condition in the most recent annual
compliance certification.

II.B.3 Conditions on Auxiliary Boiler #1 (EU#4)

II.B.3.a Condition:

Emissions of PM10 shall be no greater than 0.01 lb/MMBtu based on a 3-hour testing average. [DAQE -
AN130310012-15]. [R307-401-8]

II.B.3.a.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every five years. Tests may also be required at the
direction of the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
location.

(d) Methods.

(1) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 "SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

(2) For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR
51, Appendix M, Methods 201, 201a and 202, or other testing methods approved by EPA and
acceptable to the Director. All particulate captured shall be considered PM10. The back half
condensables shall be used for compliance demonstration as well as for inventory purposes.

(3) For stacks in which liquid drops are present, methods to eliminate the liquid drops should be
explored. If no reasonable method to eliminate the drops exists, then the following methods shall
be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing
methods approved by EPA and acceptable to the Director. The back half condensables shall also
be tested using the method specified by the Director. The portion of the front half of the catch
considered PM10 shall be based on information in Appendix B of the fifth edition of the EPA
document, AP-42, or other data acceptable to the Director.

27

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.3.a.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.3.a.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. The auxiliary boiler was last tested on December 29, 2022. Test results were
submitted to DAQ and audited in DAQC-158-23. DAQ calculated results indicate PM10 emissions of
0.002 lb/MMBtu.

II.B.3.b Condition:

Emissions of CO shall be no greater than 0.037 lb/MMBtu based on a 3-hour testing average.
[Origins: DAQE -AN130310012-15]. [R307-401-8]

II.B.3.b.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every five year. Tests may also be required at the
direction of the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
location.

(d) Methods.

(1) 40 CFR 60, Appendix A, Method 10 shall be used, or other EPA-approved testing method, as
acceptable to the Director;

28

(2) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 " SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.3.b.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.3.b.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. The auxiliary boiler was last tested on December 29, 2022. Test results were
submitted to DAQ and audited in DAQC-158-23. DAQ calculated results indicate CO emissions of
0.003 lb/MMBtu.

II.B.3.c Condition:

Emissions of NOx shall be no greater than 0.017 lb/MMBtu based on a 3-hour testing average.
[Origins: DAQE -AN130130012-15]. [R307-401-8]

II.B.3.c.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every five year. Tests may also be required at the
direction of the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA)approved access shall be provided to the test
location.

29

(d) Methods.

(1) 40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E shall be used, or other EPA-approved
testing method, acceptable to the Director;

(2) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 " SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.3.c.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.3.c.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. The auxiliary boiler was last tested on December 29, 2022. Test results were
submitted to DAQ and audited in DAQC-158-23. DAQ calculated results indicate NOX emissions of
0.016 lb/MMBtu.

II.B.3.d Condition:

The permittee shall maintain records of the amount of fuel combusted during each calendar month for
each affected emission unit. [40 CFR 60.48c(g)]. [40 CFR 60 Subpart Dc]

II.B.3.d.1 Monitoring:

Fuel consumption for each affected emission unit shall be determined by a fuel meter, vendor
supplied information, or other method approved by the Director.

II.B.3.d.2 Recordkeeping:

Records of the amounts of each fuel combusted during each month for each affected unit shall be
maintained as described in Provision I.S.1 of this permit.

30

II.B.3.d.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Fuel usage records were available during this inspection.

II.B.3.e Condition:

The permittee shall conduct a performance tune-up annually. [40 CFR 63.7500(a)(1), Table 3].
[40 CFR 63 Subpart DDDDD]

II.B.3.e.1 Monitoring:

The permittee shall conduct an annual performance tune-up according to 40 CFR 60.7540(a)(10)
and each annual tune-up shall be no more than 13 months after the previous tune-up. If the unit is
not operating on the required date for a tune-up, the tune-up shall be conducted within 30
calendar days of startup. [40 CFR 63.7515(d), 40 CFR 63.7540(a)(10), 40 CFR 63.7540(a)(13)].
[40 CFR 63 Subpart DDDDD]

II.B.3.e.2 Recordkeeping:

The permittee shall keep all the records, as applicable, as specified in 40 CFR 63.7555(a) and
63.7560. Records shall be maintained in accordance with Provision I.S.1 of this permit. [40 CFR
63 Subpart DDDDD]

II.B.3.e.3 Reporting:

The permittee shall submit annual compliance report, as applicable, as specified in 40 CFR
63.7550(b)(1) through (5). [40 CFR 63 Subpart DDDDD]

Status: In compliance. The source maintains records of annual tune-ups. Tune-ups are performed no more
than 13 months after the previous tune-up. The latest annual tune-up was performed by contractor
MSI on December 5-6, 2023. Annual tune-up reports have been submitted.

II.B.3.f Condition:

Visible emissions shall be not greater than 10% opacity from the auxiliary boiler.
[DAQE-AN130310012-15]. [R307-401-8]

II.B.3.f.1 Monitoring:

The annual certification required for this permit condition will serve as monitoring.

II.B.3.f.2 Recordkeeping:

The annual certification required for this permit condition shall be maintained as described in
Provision I.S.1 of the permit.

31

II.B.3.f.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. The source certified compliance with this condition in the most recent annual
certification.

II.B.4 Condition on Emergency Diesel Generator #1 (EU #6)

II.B.4.a Condition:

Visible emissions shall be no greater than 20 percent opacity, except for stationary operation not
exceeding three minutes in any hour. [Origins: DAQE -AN130310012-15]. [R307-401-8]

II.B.4.a.1 Monitoring:

During any period that the emergency generator(s) is(are) operated for longer than 12 hours
consecutively, visual observation(s) of each generator exhaust shall be made by an individual
trained on the observation procedures of 40 CFR 60, Appendix A, Method 9. The individual is
not required to be a certified visual emissions observer. If any visible emissions are observed,
then a 6-minute opacity determination shall be performed in accordance with 40 CFR 60,
Appendix A, Method 9, or other EPA-approved testing method, as acceptable to the Director, by
a certified visual emissions observer. If the generator(s) continue to operate on consecutive days
following the initial observation, an opacity determination shall be performed on a daily basis.

II.B.4.a.2 Recordkeeping:

The permittee shall record the date of each visual opacity survey and keep a list of the emission
points checked during the visual opacity survey. The permittee shall also keep a log of the
following information for each observed visual emission: date and time visual emissions
observed, emission point location and description, time and date of opacity test, and percent of
opacity. The records required by this provision and all data required by 40 CFR 60, Appendix A,
Method 9, or other EPA-approved testing method, as acceptable to the Director, shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.a.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. This unit did not operate for more than 12 hours consecutively during the 12-month
period preceding this inspection.

II.B.5 Conditions on Emergency Diesel Fire Pump (EU#7)

II.B.5.a Condition:

The permittee shall operate the emergency affected emission unit according to the requirements in
paragraphs (1) through (3). In order for the engine to be considered an emergency stationary ICE under
32

40 CFR 60 Subpart IIII, any operation other than as described in 40 CFR 60.4211(f), is prohibited. If the
engine is not operated according to the requirements in 40 CFR 60.4211(f), it will not be considered an
emergency engine and shall meet all requirements for non-emergency engines.

(1) There is no time limit on the use of emergency stationary ICE in emergency situations.

(2) Emergency stationary ICE may be operated for any combination of the purposes specified in 40 CFR
60.4211(f)(2)(i) for a maximum of 100 hours per calendar year. Any operation for non-emergency
situations as allowed by 40 CFR 60.4211(f)(3) counts as part of the 100 hours per calendar year allowed
by this paragraph.

(a) Emergency stationary ICE may be operated for maintenance checks and readiness testing, provided
that the tests are recommended by federal, state or local government, the manufacturer, the vendor, the
regional transmission organization or equivalent balancing authority and transmission operator, or the
insurance company associated with the engine. A petition for approval of additional hours to be used for
maintenance checks and readiness testing is not required if the permittee maintains records indicating that
federal, state, or local standards require maintenance and testing of emergency ICE beyond 100 hours per
calendar year.

(3) The permittee may operate the emergency stationary ICE up to 50 hours per calendar year in non-
emergency situations as specified in 40 CFR 60.4211(f)(3). [40 CFR 60.4211(f)].
[40 CFR 60 Subpart IIII]

II.B.5.a.1 Monitoring:

The permittee shall install a non-resettable hour meter if one is not already installed. [40 CFR
60.4209(a)].

Records required for this permit condition shall also serve as monitoring.

II.B.5.a.2 Recordkeeping:

Records of each affected emission unit shall be kept on a monthly basis in an operation and
maintenance log. Records shall distinguish between maintenance-related hours and emergency
use-related hours. If additional hours are to be used for maintenance checks and readiness testing,
the permittee shall maintain records indicating that federal, state, or local standards require
maintenance and testing of emergency ICE beyond 100 hours per calendar year. (Origin: 40 CFR
60.4211(f))

Starting with the model years in Table 5 of 40 CFR 60 Subpart IIII, if an affected emission unit
does not meet the standards applicable to non-emergency engines in the applicable model year,
the permittee shall keep records of the operation of the engine in emergency and non-emergency
service that are recorded through the non-resettable hour meter. The permittee shall record the
time of operation of the engine and the reason the engine was in operation during that time.
(Origin: 40 CFR 60.4214(b)).

Records shall be maintained in accordance with Provision I.S.1 of this permit.

33

II.B.5.a.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Records were reviewed onsite and indicated compliance with this condition. The
generator is normally operated for 30 minutes weekly for maintenance and readiness testing, and
operated 24.5 hours in calendar year 2023.

II.B.5.b Condition:

Affected emission units with a displacement of less than 30 liters per cylinder shall comply with the
applicable emission standards in Table 4 of 40 CFR 60 Subpart IIII, for all pollutants.

If the permittee conducts performance tests in-use on emergency stationary CI ICE with a displacement of
less than 30 liters per cylinder they shall meet the not-to-exceed (NTE) standards as indicated in 40 CFR
60.4212. The performance test must be conducted according to the in-use testing procedures in 40 CFR
part 1039, subpart F, for stationary CI ICE with a displacement of less than 10 liters per cylinder, and
according to 40 CFR part 1042, subpart F, for stationary CI ICE with a displacement of greater than or
equal to 10 liters per cylinder and less than 30 liters per cylinder. [40 CFR 60.4205(c) and 40 CFR
60.4212]. [40 CFR 60 Subpart IIII]

II.B.5.b.1 Monitoring:

The permittee shall comply by purchasing an engine certified to the emission standards in 40
CFR 60.4205(c) for the same model year and maximum engine power. The engine must be
installed and configured according to the manufacturer's emission-related specifications, except
as specified below. The permittee can only change those emission-related settings that are
permitted by the manufacturer. (Origin: 40 CFR 60.4211(c)) The permittee shall document
activities performed to assure proper operation and maintenance.

If the permittee does not install, configure, operate, and maintain affected emission units and
control devices according to the manufacturer's emission-related written instructions, or changes
emission-related settings in a way that is not permitted by the manufacturer, the permittee shall
demonstrate compliance as follows:

(a) Keep a maintenance plan and records of conducted maintenance to demonstrate compliance;
and

(b) To the extent practicable, maintain and operate the engine in a manner consistent with good
air pollution control practice for minimizing emissions; and

(c)The permittee shall conduct an initial performance test to demonstrate compliance with the
applicable emission standards within 1 year of such action. (Origin: 40 CFR 60.4211(g)(2)). [40
CFR 60 Subpart IIII]

II.B.5.b.2 Recordkeeping:

Records shall be maintained as described in Provision I.S.1 of this permit.

34

II.B.5.b.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Only DAQ permitted engines have been installed. No performance tests have been
conducted. Maintenance records have been maintained.

II.B.5.c Condition:

The permittee shall purchase diesel fuel that meets the following standards of 40 CFR 1090.305 for non-
road diesel fuel. [40 CFR 60.4207(b)]. [40 CFR 60 Subpart IIII]

II.B.5.c.1 Monitoring:

Records required for this permit condition will serve as monitoring requirement.

II.B.5.c.2 Recordkeeping:

For each fuel load received, the permittee shall maintain either fuel receipt records or other
documentation showing fuel meets the specifications of ASTM D975 for the cetane index and
sulfur content for Grades No. 1-D S15 or 2-D S15 diesel. The permittee shall maintain
documentation demonstrating compliance with the condition. These records shall be maintained
in accordance with Provision I.S.1. of this permit.

II.B.5.c.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. Records are kept and indicated low sulfur diesel with a cetane index of 40 or higher
was purchased.

II.B.5.d Condition:

Visible emissions shall be no greater than 20 percent opacity, except for stationary operation not
exceeding three minutes in any hour. [Origins: DAQE -AN130310012-15]. [R307-401-8]

II.B.5.d.1 Monitoring:

During any period that the Emergency Diesel Fire Pump is operated for longer than 12 hours
consecutively, visual observation(s) of the engine exhaust shall be made by an individual trained
on the observation procedures of 40 CFR 60, Appendix A, Method 9. The individual is not
required to be a certified visual emissions observer. If any visible emissions are observed, then a
6-minute opacity determination shall be performed in accordance with 40 CFR 60, Appendix A,
Method 9, or other EPA-approved testing method, as acceptable to the Director, by a certified
visual emissions observer. If the Emergency Diesel Fire Pump continues to operate on
consecutive days following the initial observation, an opacity determination shall be performed
on a daily basis.

35

II.B.5.d.2 Recordkeeping:

The permittee shall record the date of each visual opacity survey and keep a list of the emission
points checked during the visual opacity survey. The permittee shall also keep a log of the
following information for each observed visual emission: date and time visual emissions
observed, emission point location and description, time and date of opacity test, and percent of
opacity. The records required by this provision and all data required by 40 CFR 60, Appendix A,
Method 9, or other EPA-approved testing method, as acceptable to the Director, shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.5.d.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. This unit did not operate for 12 or more hours consecutively during the 12-month
period preceding this inspection.

II.B.6 Conditions on Block #2 Combustion Gas Turbines (EU#11)

II.B.6.a Condition:

Emissions of NOx from each HRSG stack shall be no greater than 2.0 ppmvd @ 15% O2 and 18.1 lb/hr
based on a 3-hour block average under steady state operation, shall not exceed 25 ppmv, dry @ 15% O2
during short-term excursions, and shall not exceed 130 lb/hr based on hourly average during startup and
shutdown operation. Steady state operation, startup and shutdown and short-term excursions are defined
in Condition II.B.6.e and II.B.6.d of this permit, respectively [Origins: DAQE -AN130310012-15 & SIP
IX.H.3.c.ii.A and IX.H.3.c.iii.B.IV]. [R307-110-17, R307-401-8, R307-403-3(3)(a)(LAER)]

II.B.6.a.1 Monitoring:

The permittee shall install, certify, maintain, operate, and quality-assure a continuous emissions
monitoring systems (CEMS) to determine compliance with the applicable NOx limitations as
specified below:

(a) Each NOx and diluent CEMS must be installed and certified according to Performance
Specification 2 (PS 2) in Appendix B of 40 CFR 60, except the 7-day calibration drift is based on
unit operating days, not calendar days. Procedure 1 in Appendix F of 40 CFR 60 is not required.
Alternatively, a NOx diluent CEMS that is installed and certified according to Appendix A of 40
CFR 75 shall be acceptable for use. The relative accuracy test audit (RATA) of the CEMS shall
be performed on a lb/MMBtu basis.

(b) As specified in 40 CFR 60.13(e)(2), during each full unit operating hours, both the NOx
monitor and the diluent monitor must complete a minimum of one cycle of operation (sampling,
analyzing, and data recording) for each 15-minute quadrant of the hour. For partial unit operating
hours, at least one valid data point must be obtained with each monitor for each quadrant of the
hour in which the unit operates. For unit operating hours in which required quality assurance and
maintenance activities are performed on the CEMS, a minimum of two valid data points (one in
each of two quadrants) are required for each monitor to validate the NOx emission rate for the
hour.

36

(c) Each fuel flowmeter shall be installed, calibrated, maintained, and operated according to the
manufacturer's instructions. Alternatively, fuel flowmeters that meet the installation, certification,
and quality assurance requirements of Appendix D of 40 CFR 75 shall be acceptable for use.

(d) Each watt meter, steam flow meter, and each pressure or temperature measurement device
shall be installed, calibrated, maintained, and operated according to manufacturer's instructions.

(e) The permittee shall develop and keep on-site a quality assurance (QA) plan for all of the
continuous monitoring equipment described in paragraphs above. For the CEMS and fuel flow
meters, the permittee may satisfy the requirements of this paragraph by implementing the QA
program and plan described in section 1 of Appendix B to 40 CFR Part 75.

(f) For purposes of identifying excess emissions, CEMS data must be reduced to hourly averages
as specified in 40 CFR 60.13(h).

(i) For each unit operating hour in which a valid hourly average, as described in paragraph (b) of
this section, is obtained for both NOx and diluent, the data acquisition and handling system must
calculate and record the hourly NOx emission rate in units of applicable NOx emission standard of
this permit condition, using the appropriate equation from Method 19 in Appendix A of 40 CFR
60. For any hour in which the hourly average O2 concentration exceeds 19.0 percent O2, a diluent
cap value of 19.0 percent O2 or 1.0 percent CO2 (as applicable) may be used in the emission
calculation.

(ii) If the permittee has installed a NOx CEMS to meet the requirements of 40 CFR Part 75, only
quality assured data from CEMS shall be used to identify excess emission. Periods where the
missing data substitution procedures in Subpart D of 40 CFR 75 are applied shall be reported as
monitor downtime in the excess emissions and monitoring performance report required under 40
CFR 60.7(c).

(iii) All required fuel flow rate, temperature, pressure, and megawatt data shall be reduced to
hourly averages. The calculated hourly average emission rates shall be used to assess excess
emissions on a 3-hour block average basis.

(g) During short-term excursions, NOx emission shall be calculated and averaged using the date
collected from the CEMS during this period of time.

(h) During startup or shutdown, hourly NOx emissions shall be calculated for each full unit
operating hour and each partial operating hour, respectively. [40 CFR 60 Subpart KKKK]

II.B.6.a.2 Recordkeeping:

Results of NOx monitoring shall be recorded and maintained as required in R307-170, 40 CFR 60
Subpart KKKK, 40 CFR 75 Subpart F, and as described in Provision I.S.1 of this permit.

II.B.6.a.3 Reporting:

(a) The permittee shall comply with the reporting provisions in R307-170-9, 40 CFR 75 Subpart
G, 40 CFR 60 Subpart KKKK and all the reporting provisions contained in Section I of this
permit.

37

(b) The permittee shall submit reports of excess emissions and monitor downtime, in accordance
with 40 CFR 60.7(c). Excess emissions shall be reported for all periods of unit operation,
including startup, shutdown and malfunction. For the purpose of reports required under 40 CFR
60.7(c), periods of excess emissions and monitor downtime that shall be reported are defined as
follows:

(1) An hour of excess emissions under steady state operation shall be any unit operating period in
which the 3-hour block average NOx concentration exceeds applicable emission standard in this
permit condition. A "3-hour block average NOx emission rate'' is the arithmetic average of the
valid NOx emission rate in ppm measured by the CEMS for each operating hour during fixed 3-
hour blocks beginning at midnight. The permittee shall calculate the 3-hour block average if a
valid NOx emission rate is obtained for at least 2 of the 3 hours.

(2) An hour of excess emission during short-term excursions, startup or shutdown shall be any
unit operating period in which hourly average NOx concentration exceeds applicable emission
standards in this permit condition. For partial unit operating hours during short-term excursions,
startup, or shutdown, at least one valid data point must be obtained with each monitor for each
quadrant of hour in which the unit operates. The data obtained during the partial unit operating
hours shall be used to calculate the average emissions.

(3) A period of monitor downtime shall be any unit operating hour in which the data for any of
the following parameters are either missing or invalid: NOx concentration, CO2 or O2
concentration, fuel flow rate, or megawatts.

(4) For operating periods during which multiple emissions standards apply, the applicable
standard is the average of the applicable standards during each hour. For hours with multiple
emissions standards, the applicable limit for that hour is determined based on the condition that
corresponded to the more stringent standard. (5) All reports of excess emissions and monitor
downtime shall be postmarked by the 30th day following the end of each calendar quarter.

(c) The quarterly reports required in R307-170-9 and 40 CFR 75 Subpart G are considered
prompt notification of permit deviations required in Provision I.S.2.c of this permit if all
information required by Provision I.S.2.c is included in the report.

Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.6.b Condition:

Emissions of NOx shall be no greater than 15 ppmvd @ 15% O2 (0.43 lb/MWh) from each turbine based
on a 30-unit operating day rolling average, as described in 40 CFR 60.4380(b)(1). [40 CFR 60.4320(a)].
[40 CFR 60 Subpart KKKK]

II.B.6.b.1 Monitoring:

The permittee shall install, certify, maintain, operate, and quality-assure a continuous emissions
monitoring systems (CEMS) to determine compliance with the applicable NOx limitations as
specified below:

(a) Each NOx and diluent CEMS must be installed and certified according to Performance
Specification 2 (PS 2) in Appendix B of 40 CFR 60, except the 7-day calibration drift is based on
unit operating days, not calendar days. Procedure 1 in Appendix F of 40 CFR 60 is not required.
38

Alternatively, a NOx diluent CEMS that is installed and certified according to Appendix A of 40
CFR 75 shall be acceptable for use. The relative accuracy test audit (RATA) of the CEMS shall
be performed on a lb/MMBtu basis.

(b) As specified in 40 CFR 60.13(e)(2), during each full unit operating hours, both the NOx
monitor and the diluent monitor must complete a minimum of one cycle of operation (sampling,
analyzing, and data recording) for each 15-minute quadrant of the hour. For partial unit operating
hours, at least one valid data point must be obtained with each monitor for each quadrant of the
hour in which the unit operates. For unit operating hours in which required quality assurance and
maintenance activities are performed on the CEMS, a minimum of two valid data points (one in
each of two quadrants) are required for each monitor to validate the NOx emission rate for the
hour.

(c) Each fuel flowmeter shall be installed, calibrated, maintained, and operated according to the
manufacturer's instructions. Alternatively, fuel flowmeters that meet the installation, certification,
and quality assurance requirements of Appendix D of 40 CFR 75 shall be acceptable for use.

(d) Each watt meter, steam flow meter, and each pressure or temperature measurement device
shall be installed, calibrated, maintained, and operated according to manufacturer's instructions.

(e) The permittee shall develop and keep on-site a quality assurance (QA) plan for all of the
continuous monitoring equipment described in paragraphs above. For the CEMS and fuel flow
meters, the permittee may satisfy the requirements of this paragraph by implementing the QA
program and plan described in Section 1 of Appendix B to 40 CFR Part 75.

(f) For purposes of identifying excess emissions, CEMS data must be reduced to hourly averages
as specified in 40 CFR 60.13(h).

(i) For each unit operating hour in which a valid hourly average, as described in paragraph (b) of
this section, is obtained for both NOx and diluent, the data acquisition and handling system must
calculate and record the hourly NOx emission rate in units of the applicable NOx emission
standard of this permit condition, using the appropriate equation from Method 19 in Appendix A
of 40 CFR 60. For any hour in which the hourly average O2 concentration exceeds 19.0 percent
O2, a diluent cap value of 19.0 percent O2 or 1.0 percent CO2 (as applicable) may be used in the
emission calculation.

(ii) If the permittee has installed a NOx CEMS to meet the requirements of 40 CFR Part 75, only
quality assured data from CEMS should be used to identify excess emissions. Periods where the
missing data substitution procedures in Subpart D of 40 CFR 75 are applied shall be reported as
monitor downtime in the excess emissions and monitoring performance report required under 40
CFR 60.7(c).

(iii) All required fuel flow rate, temperature, pressure, and megawatt data shall be reduced to
hourly averages. The calculated hourly average emission rates shall be used to assess excess
emissions on a 30-day rolling average basis. [40 CFR 60 Subpart KKKK]

II.B.6.b.2 Recordkeeping:

Results of NOx monitoring shall be recorded and maintained as required in R307-170, 40 CFR 60
Subpart KKKK, 40 CFR 75 Subpart F, and as described in Provision I.S.1 of this permit.

39

II.B.6.b.3 Reporting:

(a) The permittee shall comply with the reporting provisions in R307-170-9, 40 CFR 75 Subpart
G, 40 CFR 60 Subpart KKKK and all the reporting provisions contained in Section I of this
permit.

(b) The permittee shall submit reports of excess emissions and monitor downtime, in accordance
with 40 CFR 60.7(c). Excess emissions shall be reported for all periods of unit operation,
including startup, shutdown and malfunction. For the purpose of reports required under 40 CFR
60.7(c), periods of excess emissions and monitor downtime that shall be reported are defined as
follows:

(1) An hour of excess emissions shall be any unit operating period in which 30-day rolling
average NOx concentration exceeds applicable NSPS emission standard of 15 ppm (15% O2) or
0.43 lb/MWh as required in 40 CFR 60.4350(h). A "30-day rolling average NOx emission rate'' is
the arithmetic average of all hourly NOx emission data in ppm or lb/MWh measured by the
CEMS for a given day and the 29-unit operating days average NOx emission rates immediately
preceding that unit operating day. A new 30-day average is calculated each unit operating day as
the average of all hourly NOx emissions rates for the preceding 30-unit operating days if a valid
NOx emission rate is obtained for at least 75 percent of all operating hours. [40 CFR 60.4350(h)]

(2) A period of monitor downtime shall be any unit operating hour in which the data for any of
the following parameters are either missing or invalid: NOx concentration, CO2 or O2
concentration, fuel flow rate, or megawatts.

(3) For operating periods during which multiple emissions standards apply, the applicable
standard is the average of the applicable standards during each hour. For hours with multiple
emissions standards, the applicable limit for that hour is determined based on the condition that
corresponded to the highest emissions standard.

(4) All reports of excess emissions and monitor downtime shall be postmarked by the 30th day
following the end of each calendar quarter.

(c) The quarterly reports required in R307-170-9 and 40 CFR 75 Subpart G are considered
prompt notification of permit deviations required in Provision I.S.2.c of this permit if all
information required by Provision I.S.2.c is included in the report.

Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.6.c Condition:

Emissions of CO from each HRSG stack shall be no greater than 3.0 ppmvd @ 15% O2 and 16.6 lb/hr
based on 3-hour block average under steady state operation, shall not exceed 50 ppmv, dry @ 15% O2
during short-term excursions, and shall not exceed 3,000 lb/hr during startup and shutdown operations.
Steady state operation, startup and shutdown and short-term excursions are defined in Condition II.B.6.e
and II.B.6.d of this permit, respectively [Origins: DAQE -AN130310012-15]. [R307-401-8]

40

II.B.6.c.1 Monitoring:

The emission of CO shall be monitored by continuous emission monitoring systems (CEMS)
consisting of CO and O2 monitors. The O2 monitor shall be used to adjust the measured CO
concentrations to 15% O2. The permittee shall calibrate, maintain, and operate a CEMS as
required by R307-170 to determine compliance with CO concentration. The quality assurance
requirements of R307-170, Continuous Emission Monitoring Systems Program shall be used to
fulfill data quality assurance requirements.

(1) Under steady state operations, the hourly average of CO emissions shall be calculated every
hour and the 3-hour rolling average shall be calculated using the hourly average data.

(2) During short-term excursions, the CO emission rate shall be calculated and averaged using the
data collected from the CEMS during this period of time.

(3) During startups or shutdowns, the hourly CO emissions shall be calculated for each full unit
operating hour and each partial operating hour, respectively.

II.B.6.c.2 Recordkeeping:

Results of CO monitoring shall be recorded and maintained as required in R307-170 and as
described in Provision I.S.1 of this permit.

II.B.6.c.3 Reporting:

The permittee shall comply with the reporting provisions in R307-170-9 and all the reporting
provisions contained in Section I of this permit. The quarterly reports required in R307-170-9 is
considered prompt notification of permit deviations required in Provision I.S.2.c of this permit if
all information required by Provision I.S.2.c is included in the report.

Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.6.d Condition:

Short-term excursions are defined as 15-minute periods designated by the permittee that are the direct
result of transient load conditions when the 15-minute average CO or NOx concentration exceeds 3.0
ppmv and 2.0 ppmv, dry @ 15% O2 respectively. Short-term excursions shall not exceed four consecutive
15-minute periods and shall not exceed a cumulative total of 160 hours annually. Transient load
conditions include the following:

(1) Initiation/shutdown of combustion turbine inlet air cooling

(2) Rapid combustion turbine load changes

(3) Initiation/shutdown of HRSG duct burners

(4) Provision of Ancillary Services and Automatic Generation Control. [DAQE-AN130310012-15 & SIP
IX.H.3.iii.B.III and C.III]. [R307-110-17, R307-401-8]

41

II.B.6.d.1 Monitoring:

Total hours of short-term excursions shall be determined by January 30 of each year using the
records required in this permit condition.

II.B.6.d.2 Recordkeeping:

Records of each short-term excursion shall be maintained in accordance with Provision I.S.1 of
this permit. The records shall include

(a) Date and time that the short-term excursions occur

(b) Duration (total minutes or hours) of each short-term excursion

(c) 15-minute average CO and NOx concentrations for each short-term excursion

(d) Cause of each short-term excursion.

II.B.6.d.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Short term excursion were reviewed onsite during this inspection. Three 15-minute
excursions were recorded on Block #2 during calendar year 2023. Date and time, duration, cause,
and pollutant concentrations are recorded, and some information is reported in quarterly CEM
reports.

II.B.6.e Condition:

Steady state operation means all periods of combustion turbine operation, except for periods of startup
and shutdown as defined below, and periods of transient load conditions as defined in II.B.6.d of this
permit. Startup is defined as the period beginning with turbine initial firing until the unit stabilizes at the
NOx and CO emission limits of 2.0 ppmvd (18.1 lb/hr) and 3.0 ppmvd, @ 15% O2, respectively, for
steady state operation. Shutdown is defined as the period beginning with the initiation of turbine
shutdown sequence and ending with the cessation of firing of the gas turbine engine. Startup and
shutdown events shall not exceed 553.6 hours per turbine per rolling 12-month period and are counted
toward the applicable annual emission limitations. The cumulative startup and shutdown period shall not
exceed 8 hours per turbine in any one calendar day, commencing at midnight and ending at the following
midnight. [DAQE-AN130310012-15 & SIP IX.H.3.c.B.I and II]. [R307-110-17, R307-401-8]

II.B.6.e.1 Monitoring:

Daily totals shall be calculated when startup or shutdown occurs. Total hours of startup and
shutdown shall be determined by January 30 of each year using the records required in this permit
condition.

42

II.B.6.e.2 Recordkeeping:

Records of each startup and shutdown shall be maintained in accordance with Provision I.S.1 of
this permit. The records shall include:

(a) Date and time that the startup or shutdown occurs,

(b) Duration (total minutes or hours) for each startup or shutdown event,

(c) Hourly average CO and NOx concentration during startup or shutdown event,

(d) Cause of each startup or shutdown.

II.B.6.e.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. Records were provided and reviewed during this inspection. The 8 hour daily
cumulative startup and shutdown limit was not exceeded during the 12-month period preceding
this inspection. The 613.5 hours per turbine per 12-month period was not exceeded. 82.6 combined
hours were recorded during calendar year 2023.

II.B.6.f Condition:

Emissions of PM10/PM2.5 shall be no greater than 14 lb/hr (with duct firing) from each HRSG stack based
on a 30-day rolling average. [DAQE-AN130310012-15]. [R307-401-8, R307-403-3(3)(a)(LAER)]

II.B.6.f.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every year. Tests may also be required at the direction of
the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
location.

(d) Methods.

(1) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 "SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

43

(2) For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR
51, Appendix M, Methods 201, 201a and 202, or other testing methods approved by EPA and
acceptable to the Director. All particulate captured shall be considered PM10 /PM2.5
(3) For stacks in which liquid drops are present, methods to eliminate the liquid drops should be
explored. If no reasonable method to eliminate the drops exists, then the following methods shall
be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing
methods approved by EPA and acceptable to the Director. The back half condensables shall also
be tested using the method specified by the Director. The portion of the front half of the catch
considered PM10 /PM2.5 shall be based on information in Appendix B of the fifth edition of the
EPA document, AP-42, or other data acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.6.f.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.6.f.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. Stack testing was conducted May 16-19, 2023. Results were submitted to DAQ and
are awaiting review. Contractor calculated results for PM10 were: CT21 – 11 lb/hr, CT22 – 13 lb/hr.

II.B.6.g Condition:

Emissions of VOC shall be no greater than 2.8 ppvmd at 15% O2 from each HRSG stack based on a 3-
hour testing average. [DAQE-AN130310012-15]. [R307-401-8]

II.B.6.g.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every two years. Tests may also be required at the
direction of the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

44

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
location.

(d) The following methods shall be used to measure VOC emissions: 40 CFR 60, Appendix A,
Method 25A, or other EPA-approved testing method, as acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.6.g.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.6.g.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. Stack testing was conducted May 2-3, 2022. Results were submitted to DAQ and
audited in DAQC-847-22. DAQ calculated test results for VOC were: CT21 – 0.0 ppmdv (corrected
to 15% O2), CT22 – 0.1 ppmdv (corrected to 15% O2).

II.B.6.h Condition:

Total CO2e emissions shall not exceed 950 lb/MWh(g) based on 12-month rolling average. [DAQE-
AN130310012-15]. [R307-401-8]

II.B.6.h.1 Monitoring:

The hourly heat input and the hourly gross generation for each turbine and HSRG shall be
obtained from the data submitted to the Acid Rain database and summed over the appropriate 12-
month period. The total heat input will then be multiplied by an emission factor of 121.723 lb
CO2e/MMBtu to obtain the total CO2e emissions during the 12-month period. The CO2e per
MWh(g) value shall be calculated by dividing the 12-month total CO2e emissions by the 12-
month total gross generation.

II.B.6.h.2 Recordkeeping:

Results of monitoring shall be recorded and maintained in accordance with Provision S.1 in
Section I of this permit.

45

II.B.6.h.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Records indicated CO2 emissions of less than 950 lb/MWh(g) on each unit of Block
2. During the 12-month period ending December 31, 2023, CT03 averaged 832.6 lb/MWh(g) and
CT04 averaged 840.87 lb/MWh(g).

II.B.6.i Condition:

Sulfur content of any fuel combusted shall be no greater than 0.060 lb/MMBtu. [40 CFR 60.4330(a)(2)].
[40 CFR 60 Subpart KKKK]

II.B.6.i.1 Monitoring:

In lieu of monitoring the total sulfur content of gaseous fuel combusted in the turbines, the
permittee shall use one of the following sources of information to demonstrate that the gaseous
fuel meets the definition of natural gas in 40 CFR 60.4420:

(a) The gas quality characteristics in a current, valid purchase contract, tariff sheet or
transportation contract for the gaseous fuel, specifying that the maximum total sulfur content of
the fuel is 20.0 grains/100 scf or less, has potential sulfur emissions of less than 26 ng SO2/J
(0.060 lb SO2/MMBtu) heat input; or

(b) Representative fuel sampling data which show that the sulfur content of the gaseous fuel does
not exceed 26 ng SO2/J (0.060 lb SO2/MMBtu). At a minimum, the amount of fuel sampling data
specified in Section 2.3.1.4 or 2.3.2.4 of Appendix D to 40 CFR Part 75 is required. [40 CFR 60
Subpart KKKK]

II.B.6.i.2 Recordkeeping:

Fuel receipt records showing sulfur content of the delivered fuel, gross heating value, and
density; or records of all sulfur content testing performed on the delivered fuel shall be
maintained in accordance with Provision I.S.1. of this permit.

II.B.6.i.3 Reporting:

The results of the testing shall be submitted semi-annually to the Director and to EPA. Any
deviations from this provision shall be promptly reported to the Director and to EPA; and
included in the semi-annual monitoring report. All reports shall be in accordance with Provision
I.S.2 of this permit.

Status: In compliance. The source burns only pipeline quality natural gas. A tariff sheet is available for
review.

II.B.6.j Condition:

Visible emissions shall be not greater than 10% opacity from each turbine and duct burner.
[DAQE-AN130310012-15]. [R307-401-8]

46

II.B.6.j.1 Monitoring:

The annual certification required for this permit condition will serve as monitoring.

II.B.6.j.2 Recordkeeping:

The annual certification required for this permit condition shall be maintained as described in
Provision I.S.1 of the permit.

II.B.6.j.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. The source has certified compliance with this condition in the most recent annual
compliance certification.

II.B.7 Conditions on Auxiliary Boiler #2 (EU#13)

II.B.7.a Condition:

Emissions of PM10/PM2.5 shall be no greater than 0.01 lb/MMBtu based on a 3-hour testing average.
[Origins: DAQE -AN130310012-15]. [R307-401-8]

II.B.7.a.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every five years. Tests may also be required at the
direction of the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
location.

(d) Methods.

(1) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 "SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

(2) For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR
51, Appendix M, Methods 201, 201a and 202, or other testing methods approved by EPA and
acceptable to the Director. All particulate captured shall be considered PM10 /PM2.5
47

(3) For stacks in which liquid drops are present, methods to eliminate the liquid drops should be
explored. If no reasonable method to eliminate the drops exists, then the following methods shall
be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing
methods approved by EPA and acceptable to the Director. The back half condensables shall also
be tested using the method specified by the Director. The portion of the front half of the catch
considered PM10 /PM2.5 shall be based on information in Appendix B of the fifth edition of the
EPA document, AP-42, or other data acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.7.a.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.7.a.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. Auxiliary boiler #2 was last tested October 8, 2019. Results were submitted to DAQ
and found in compliance in DAQC-1704-19. DAQ calculated test results indicated 0.004 lb/MMBtu
of PM10/PM2.5.

II.B.7.b Condition:

Emissions of CO shall be no greater than 0.037 lb/MMBtu based on a 3-hour testing average. [Origins:
DAQE -AN130310012-15]. [R307-401-8]

II.B.7.b.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every five years. Tests may also be required at the
direction of the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
48

location.

(d) Methods.

(1) 40 CFR 60, Appendix A, Method 10 shall be used, or other EPA-approved testing method, as
acceptable to the Director;

(2) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 "SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.7.b.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.7.b.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. Auxiliary boiler #2 was last tested October 8, 2019. Results were submitted to DAQ
and found in compliance in DAQC-1704-19. DAQ calculated test results indicated 0.000 lb/MMBtu
of CO.

II.B.7.c Condition:

Emissions of NOx shall be no greater than 0.017 lb/MMBtu based on a 3-hour testing average. [Origins:
DAQE -AN130130012-15]. [R307-401-8]

II.B.7.c.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every five years. Tests may also be required at the
direction of the Director at any time.

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

49

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
location.

(d) Methods.

(1) 40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E shall be used, or other EPA-approved
testing method, acceptable to the Director;

(2) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 "SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.7.c.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.7.c.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. Auxiliary Boiler #2 was last tested October 8, 2019. Results were submitted to DAQ
and found in compliance in DAQC-1704-19. DAQ calculated test results indicated 0.009 lb/MMBtu
of NOX.

II.B.7.d Condition:

Emissions of VOC shall be no greater than 0.006 lb/MMBtu based on a 3-hour testing average. [Origins:
DAQE -AN130130012-15]. [R307-401-8]

II.B.7.d.1 Monitoring:

Stack testing shall be performed as specified here:

(a) Frequency. Emissions shall be tested every five years. Tests may also be required at the
direction of the Director at any time.

50

(b) Notification. At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the test protocol. The source shall attend a pretest
conference if determined necessary by the Director.

(c) Sample Point. The emission sample point shall conform to the requirements of 40 CFR 60,
Appendix A, Method 1. In addition, Occupational Safety and Health Administration (OSHA) or
Mine Safety and Health Administration (MSHA) approved access shall be provided to the test
location.

(d) Methods.

(1) 40 CFR 60, Appendix A, Method 25A shall be used, or other EPA-approved testing method,
as acceptable to the Director;

(2) Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 " SO2
Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing
methods approved by EPA and acceptable to the Director.

(e) Calculations. To determine mass emission rates (lb/hr, etc.) the pollutant concentration as
determined by the appropriate methods above shall be multiplied by the volumetric flow rate and
any necessary conversion factors required providing the results in the specified units of the
emission limitation.

(f) Production Rate During Testing. The operational rate during all compliance testing shall be no
less than 90% of the maximum rate achieved in the previous three (3) years.

II.B.7.d.2 Recordkeeping:

Results of all stack testing shall be recorded and maintained in accordance with the associated test
method and Provision S.1 in Section I of this permit.

II.B.7.d.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate
compliance status. There are no additional reporting requirements for this provision except those
specified in Section I of this permit.

Status: In compliance. Auxiliary boiler #2 was last tested October 8, 2019. Results were submitted to DAQ
and found in compliance in DAQC-1704-19. DAQ calculated test results indicated 0.000 lb/MMBtu
of VOC.

II.B.7.e Condition:

The permittee shall maintain records of the amount of fuel combusted during each calendar month for
each affected emission unit. [40 CFR 60.48c(g)]. [40 CFR 60 Subpart Dc]

51

II.B.7.e.1 Monitoring:

Fuel consumption for each affected emission unit shall be determined by a fuel meter, vendor
supplied information, or other method approved by the Director.

II.B.7.e.2 Recordkeeping:

Records of the amounts of each fuel combusted during each month for each affected unit shall be
maintained as described in Provision I.S.1 of this permit.

II.B.7.e.3 Reporting:

There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In compliance. Fuel consumption records have been kept.

II.B.7.f Condition:

The permittee shall conduct a performance tune-up annually. [40 CFR 63.7500(a)(1), Table 3]. [40 CFR
63 Subpart DDDDD]

II.B.7.f.1 Monitoring:

The permittee shall conduct an annual performance tune-up according to 40 CFR 60.7540(a)(10)
and each annual tune-up shall be no more than 13 months after the previous tune-up. [40 CFR
63.7515]. [40 CFR 63 Subpart DDDDD]

II.B.7.f.2 Recordkeeping:

The permittee shall keep all the records, as applicable, as specified in 40 CFR 63.7555(a) and
63.7560. Records shall be maintained in accordance with Provision I.S.1 of this permit. [40 CFR
63 Subpart DDDDD]

II.B.7.f.3 Reporting:

The permittee shall submit annual compliance report, as applicable, as specified in 40 CFR
63.7550(b)(1) through (5). [40 CFR 63 Subpart DDDDD]

Status: In compliance. The source maintains records of annual tune-ups. Tune-ups are performed no more
than 13 months after the previous tune-up. The latest annual tune-up was performed by contractor
MSI on December 5-6, 2023. Annual tune-up reports have been submitted.

II.B.7.g Condition:

Visible emissions shall be not greater than 10% opacity from the auxiliary boiler.
[DAQE-AN130310012-15]. [R307-401-8]

52

II.B.7.g.1 Monitoring:

The annual certification required for this permit condition will serve as monitoring.

II.B.7.g.2 Recordkeeping:

The annual certification required for this permit condition shall be maintained as described in
Provision I.S.1 of the permit.

II.B.7.g.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. The source certified compliance with this condition in the most recent annual
compliance certification.

II.B.8 Conditions on Emergency Diesel Generator #2 (EU#14)

II.B.8.a Condition:

Generators and control devices (if any) shall be operated and maintained according to the manufacturer
emissions-related written instructions, over the entire life of the associated engine. The permittee may
only change those settings that are permitted by the manufacturer. The permittee shall also meet the
requirements of 40 CFR part 89, 94 and/or 1068, as they apply. [Origin: 40 CFR 60.4206, 40 CFR
60.4211(a)(1)-(3)]. [40 CFR 60 Subpart IIII]

II.B.8.a.1 Monitoring:

(a) The permittee shall document activities performed to assure proper operation and
maintenance.

(b) If the permittee does not install, configure, operate, and maintain affected emission units and
control devices according to the manufacturer's emission-related written instructions, or changes
emission-related settings in a way that is not permitted by the manufacturer, the permittee shall
demonstrate compliance as follows:

(i) Keep a maintenance plan and records of conducted maintenance; and

(ii) To the extent practicable, maintain and operate the engine in a manner consistent with good
air pollution control practice for minimizing emissions; and

(iii) Conduct an initial performance test to demonstrate compliance with the applicable emission
standards within 1 year of startup, or within 1 year after an engine and control device is no longer
installed, configured, operated, and maintained in accordance with the manufacturer's emission-
related written instructions, or within 1 year after changing emission-related settings in a way that
is not permitted by the manufacturer. The permittee shall conduct subsequent performance testing
every 8,760 hours of engine operation or 3 years, whichever comes first, thereafter to demonstrate
compliance with the applicable emission standards. (Origin: 40 CFR 60.4211(g)).

53

II.B.8.a.2 Recordkeeping:

Records demonstrating proper operation and maintenance shall be maintained.

Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.8.a.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. Generator #2 has been operated and maintained according to manufacturer
instructions. Maintenance activities have been recorded.

II.B.8.b Condition:

Emergency generators shall use diesel fuel that meets the requirements of 40 CFR 1090.305 for nonroad
diesel fuel.

[Origin: 40 CFR 60.4207(b)]. [40 CFR 60 Subpart IIII]

II.B.8.b.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.8.b.2 Recordkeeping:

For each fuel load received, the permittee shall maintain either fuel receipt records or other
documentation showing fuel meets the specifications of ASTM D975 for the cetane index and
sulfur content for Grades No. 1-D S15 or 2-D S15 diesel. The permittee shall maintain
documentation demonstrating compliance with the condition. These records shall be maintained
in accordance with Provision I.S.1. of this permit.

II.B.8.b.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. Records are kept and indicated low sulfur diesel with a cetane index of 40 or higher
was purchased.

II.B.8.c Condition:

The permittee shall operate the emergency affected emission unit according to the requirements in
paragraphs (1) through (3). In order for the engine to be considered an emergency stationary ICE under
40 CFR 60 Subpart IIII, any operation other than as described in 40 CFR 60.4211(f), is prohibited. If the
engine is not operated according to the requirements in 40 CFR 60.4211(f), it will not be considered an
emergency engine and shall meet all requirements for non-emergency engines.

(1) There is no time limit on the use of emergency stationary ICE in emergency situations.

54

(2) Emergency stationary ICE may be operated for any combination of the purposes specified in 40 CFR
60.4211(f)(2)(i) for a maximum of 100 hours per calendar year. Any operation for non-emergency
situations as allowed by 40 CFR 60.4211(f)(3) counts as part of the 100 hours per calendar year allowed
by this paragraph.

(a) Emergency stationary ICE may be operated for maintenance checks and readiness testing, provided
that the tests are recommended by federal, state or local government, the manufacturer, the vendor, the
regional transmission organization or equivalent balancing authority and transmission operator, or the
insurance company associated with the engine. A petition for approval of additional hours to be used for
maintenance checks and readiness testing is not required if the permittee maintains records indicating that
federal, state, or local standards require maintenance and testing of emergency ICE beyond 100 hours per
calendar year.

(3) The permittee may operate the emergency stationary ICE up to 50 hours per calendar year in non-
emergency situations as specified in 40 CFR 60.4211(f)(3). [Origin: 40 CFR 60.4211(f)].
[40 CFR 60 Subpart IIII]

II.B.8.c.1 Monitoring:

If an emergency affected emission unit does not meet the standards applicable to non-emergency
engines, the permittee shall install a non-resettable hour meter prior to startup of the engine.
[origin: 40 CFR 60.4209(a)]

Records required for this permit condition shall also serve as monitoring.

II.B.8.c.2 Recordkeeping:

Records of monitoring shall be kept on a monthly basis in an operation and maintenance log.
Records shall distinguish between maintenance-related hours and emergency use-related hours. If
maintenance and testing of a generator beyond 100 hours per calendar year are required by
Federal, State, or local standards, records of these standards shall also be kept. The permittee
shall record the time of operation of each engine and the reason the engine was in operation
during that time.

Starting with the model years in Table 5 of 40 CFR 60 Subpart IIII, if an affected emission unit
does not meet the standards applicable to non-emergency engines in the applicable model year,
the permittee shall keep records of the operation of the engine in emergency and non-emergency
service that are recorded through the non-resettable hour meter. The permittee shall record the
time of operation of the engine and the reason the engine was in operation during that time.

Records shall be maintained in accordance with Provision I.S.1 of this permit. [40 CFR
60.4211(e), and 40 CFR 60.4214(b)]. [40 CFR 60 Subpart IIII]

II.B.8.c.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. An emergency generator use log was kept and included all the required information.
No deviations were noticed. This generator operated for 25.1 hours in calendar year 2023.

55

II.B.8.d Condition:

Emergency generators shall comply with 40 CFR 60.4202, for all pollutants for the same model year and
maximum engine power.

[Origin: 40 CFR 60.4205(b)]. [40 CFR 60 Subpart IIII]

II.B.8.d.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.8.d.2 Recordkeeping:

Records of engine certifications shall be maintained indicating compliance with the above
referenced standards. Records may include labels attached to engines indicating conformance
with U.S. EPA regulations for the appropriate year.

Records shall be maintained demonstrating compliance with the manufacturer specifications for
engine installation and configuration.

Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.8.d.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. Only generators approved by DAQ have been installed.

II.B.8.e Condition:

Visible emissions shall be no greater than 20 percent opacity, except for stationary operation not
exceeding three minutes in any hour. [Origins: DAQE -AN130310012-15]. [R307-401-8]

II.B.8.e.1 Monitoring:

During any period that the emergency generator(s) is(are) operated for longer than 12 hours
consecutively, visual observation(s) of each generator exhaust shall be made by an individual
trained on the observation procedures of 40 CFR 60, Appendix A, Method 9. The individual is
not required to be a certified visual emissions observer. If any visible emissions are observed,
then a 6-minute opacity determination shall be performed in accordance with 40 CFR 60,
Appendix A, Method 9, or other EPA-approved testing method, as acceptable to the Director, by
a certified visual emissions observer. If the generator(s) continue to operate on consecutive days
following the initial observation, an opacity determination shall be performed on a daily basis.

56

II.B.8.e.2 Recordkeeping:

The permittee shall record the date of each visual opacity survey and keep a list of the emission
points checked during the visual opacity survey. The permittee shall also keep a log of the
following information for each observed visual emission: date and time visual emissions
observed, emission point location and description, time and date of opacity test, and percent
opacity. The records required by this provision and all data required by 40 CFR 60, Appendix A,
Method 9, or other EPA-approved testing method, as acceptable to the Director, shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.8.e.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. Generator #2 did not operate for 12 hours or longer during the 12-month period
preceding this inspection.

II.B.9 Conditions on Misc. Activities (EU#15)

II.B.9.a Condition:

(1) Except as provided in (2) below, visible emissions from abrasive blasting operations shall not exceed
20% opacity except for an aggregate period of three minutes in any one hour.

(2) If the abrasive blasting operation complies with the performance standards in R307-306-6, visible
emissions from the operation shall not exceed 40% opacity, except for an aggregate period of 3 minutes
in any one hour. [Origin: R307-306]. [R307-306-4]

II.B.9.a.1 Monitoring:

Visible emission evaluation of abrasive blasting operations shall be conducted at least semi-
annually in accordance with the following provisions:

(a) EPA Method 9, or other EPA-approved testing method, as acceptable to the Director, if the
affected emission unit was operated during the month. Visible emissions from intermittent
sources shall use procedures similar to Method 9, but the requirement for observations to be made
at 15 second intervals over a six-minute period shall not apply;

(b) Visible emissions from unconfined blasting shall be measured at the densest point of the
emission after a major portion of the spent abrasive has fallen out, at a point not less than five feet
nor more than twenty-five feet from the impact surface from any single abrasive blasting nozzle;

(c) An unconfined blasting operation that uses multiple nozzles shall be considered a single
source unless it can be demonstrated by the permittee that each nozzle, measured separately,
meets the emission and performance standards provided in R306-306-4]

(d) Visible emissions from confined blasting shall be measured at the densest point after the air
contaminant leaves the enclosure.

57

II.B.9.a.2 Recordkeeping:

Results of monitoring and records of all data required by 40 CFR 60, Appendix A, Method 9 shall
be maintained in accordance with Provision I.S.1 of this permit.

II.B.9.a.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In compliance. Some abrasive blasting occurred on Block #2 during the 12-month period preceding
this inspection. This abrasive blasting was confined. Visible emissions observations were performed
and recorded.

EMISSION INVENTORY: Taken from DAQ’s 2022 emission inventory database:

Emissions in tons Pollutant
207.87
171.63
Ammonia
Carbon Monoxide
16.54 Formaldehyde
184.09 Nitrogen Oxides
68.89 Particulate Matter - PM10
59.59 Particulate Matter - PM2.5
14.25 Sulfur Oxides
48.99 Volatile Organic Compounds

PREVIOUS ENFORCEMENT
ACTIONS: None in the past 5 years.

COMPLIANCE STATUS &
RECOMMENDATIONS: Compliance status is pending review of stack testing on CT11.
The stack test auditor will make a compliance determination and
recommendation for permit condition II.B.2.g. PacifiCorp Lake
Side should be found in compliance with all other permit
conditions evaluated during this inspection.

HPV STATUS: Not applicable

COMPLIANCE ASSISTANCE: No

RECOMMENDATION FOR
NEXT INSPECTION: Inspect as usual

ATTACHMENT: VEO/Inspection Form